Grid Code Proposal for Solar Photovoltaics Power Plant in

Master’s Degree

Qualification

Grid Code Proposal for

Solar Photovoltaics Power Plant in Indonesia

REPORT

Author: INDRA Pratama Supervisor: ANDREAS Sumper & EDUARD Bullich-Massagué

Completion date: June 2019

Barcelona School of Industrial Engineering

Page 2 Grid Code Proposal for Solar Photovoltaics Power Plant in Indonesia

Grid Code Proposal for Solar Photovoltaics Power Plant in Indonesia Page 3

Abstract

This master thesis deals with the grid code design for solar photovoltaics power plant (PVPP).

For this purpose, three approaches are identified: (1) Several sets of international grid codes

for large scale solar PVPP are studied from operational perspective such as voltage and

frequency boundaries, active power and frequency support, reactive power and voltage

support and fault-ride-through. The chosen sets of grid codes are of Puerto Rico, Germany,

Denmark and European Union since they are mature enough and well-developed to study.

Additionally, the core of this master thesis is to study the existing electricity transmission and

distribution system in Indonesia along with current grid codes. The aforementioned research

of international grid codes serves as a foundation to propose suitable grid code design or

update existing grid code for solar PVPP in Indonesia. (2) the introduction and characteristics

of solar photovoltaics power plant (PVPP) in which the basic electrical components (e.g. PV

panel, PV inverter and transformer) are discussed. Besides, inverter topology (e.g. central

inverter topology, string inverter topology, multistring inverter topology, etc.) and internal

collection grid configuration (e.g. radial configuration, ring configuration, star configuration) is

explained. In addition, the brief modelling approach for each electrical component is given in

this chapter. (3) In the later part of this master thesis, a 1 MW solar PVPP along with the

electrical grid is modelled and simulated to test the proposed grid code for solar PVPP in

Indonesia. The proposed grid codes that are tested and simulated are active power and

frequency regulation particularly absolute production (i.e. power curtailment) through

maximum power point tracking (MPPT) function in PV inverter as well as reactive power and

voltage support regulation such as function of voltage control, reactive power control and

power factor control.

Page 4 Grid Code Proposal for Solar Photovoltaics Power Plants in Indonesia

Contents

ABSTRACT ___________________________________________________ 3

LIST OF FIGURES _____________________________________________ 7

LIST OF TABLES _____________________________________________ 10

THESIS OUTLINE _____________________________________________ 16

NOMENCLATURE ____________________________________________ 18

INTRODUCTION __________________________________________ 19

Overview ...................................................................................................... 19

REVIEW OF INTERNATIONAL GRID CODES __________________ 22

Necessity of Grid Code ................................................................................ 22

Contents of Grid Code ................................................................................. 27

Voltage and Frequency Boundaries ................................................................ 28

Active Power and Frequency Control Functions ............................................. 28

Reactive Power and Voltage Control Functions .............................................. 30

Fault-Ride-Through (FRT) Capability .............................................................. 32

Grid Codes of Puerto Rico ........................................................................... 35

2.3.1 Voltage and Frequency Boundaries ................................................................ 35

2.3.2 Active Power and Frequency Support ............................................................. 36

2.3.3 Reactive Power and Voltage Support ............................................................. 39

2.3.4 Fault-Ride-Through Requirement ................................................................... 39

Grid Codes of Germany ............................................................................... 41




2.4.4 Fault-Ride-Through Capability ........................................................................ 45

Grid Codes of Denmark ............................................................................... 46





2.6 Grid Codes of European Union .................................................................... 52






2.7 Summary ...................................................................................................... 59

GRID CODE PROPOSAL FOR SOLAR PVPP IN INDONESIA _____ 63

3.1 Existing Electricity Transmission and Distribution System ........................... 64

3.2 Current Grid Codes of Indonesia .................................................................. 66





3.3 Grid Code Proposal ...................................................................................... 70





INTRODUCTION AND CONTROL OF SOLAR PHOTOVOLTAICS

POWER PLANT __________________________________________ 81

Introduction ................................................................................................... 81

PV Panels ..................................................................................................... 84

PV Inverters .................................................................................................. 86

4.3.1 Local Control of PV Inverter ............................................................................ 88

Master Control by Power Plant Controller .................................................... 91

MODELLING AND SIMULATION OF SOLAR PVPP _____________ 95

PV Arrays ..................................................................................................... 95

PV Inverters ................................................................................................ 101

5.2.1 Aggregated PV Inverter Model .......................................................................... 104

PV Plant Model ........................................................................................... 104

RESULTS AND DISCUSSION ______________________________ 106

Maximum Power Point Tracking (MPPT) ................................................... 106

6.2.1 Maximum Power Point (MPP) Mode ............................................................. 106

6.2.1 Active Power Setpoint Mode (i.e. Power Curtailment) ................................... 108

Voltage Control and Reactive Power Regulation Action ............................ 110

6.2.2 Reactive Power Control ................................................................................ 115

6.2.3 Power Factor Control .................................................................................... 117

CONCLUSION __________________________________________ 120

BIBLIOGRAPHY _________________________________________ 122



List of Figures

Figure 1. 1 Global cumulative PV installation in 2014 and 2017 [9] ...................................... 20

Figure 2. 1 Puerto Rico’s electricity generation mix in 2014 and 2017 [14] [15] .................... 23

Figure 2. 2 Germany’s electricity generation mix in 2010 and 2017 [16] [17] ....................... 24

Figure 2. 3 Denmark` electricity generation mix in 2010 and 2016 [18] ................................ 24

Figure 2. 4 EU’s electricity generation mix in 2000 and 2016 [19] ........................................ 25

Figure 2. 5 EU´s installed power capacity in 2005 and 2017 [20] ......................................... 26

Figure 2. 6 Frequency response or control [adapted from [12]] ............................................ 29

Figure 2. 7 Absolute production, delta production and power gradient [adapted from [27]] .. 30

Figure 2. 8 Voltage control with droop function [adapted from [28]] ...................................... 31

Figure 2. 9 Automatic power factor control [adapted from [27]] ............................................ 32

Figure 2. 10 Normal operating zones as functions of power factor and reactive power ........ 32

Figure 2. 11 LVRT Capability [12] ........................................................................................ 33

Figure 2. 12 HVRT capability [12] ......................................................................................... 34

Figure 2. 13 Reactive current injection ................................................................................. 35

Figure 2. 14 FRT requirement [adapted from [29]] ............................................................... 46

Figure 2. 15 The map of synchronous areas in Europe [36] ................................................. 54

Figure 2. 16 LVRT requirement due to symmetrical fault ..................................................... 58

Figure 3. 1 Indonesia´s installed power capacity .................................................................. 63

Figure 3. 2 Indonesia´s energy mix by 2025 [39] .................................................................. 64

Figure 3. 3 Illustrative single line diagram of generation, transmission and .......................... 65


Figure 4. 1 PV inverter topologies [adapted from [58]]. ........................................................ 82

Figure 4. 2 Radial collection grid topology [58] ..................................................................... 83

Figure 4. 3 Ring collection grid topology [58] ........................................................................ 83

Figure 4. 4 Star collection grid topology [58]......................................................................... 84

Figure 4. 5 General model of solar cell circuit [adapted from [[64]] ....................................... 85

Figure 4. 6 General equivalent circuits of PV [64] ................................................................. 86

Figure 4. 7 Electrical scheme of on-grid solar PVPP under study [adapted from [70]] .......... 87

Figure 4. 8 Electrical scheme of average on-grid solar PVPP model under study [adapted from

[45]] ...................................................................................................................................... 88

Figure 4. 9 Electrical scheme of average PV inverter model under study [adapted from [45]]

............................................................................................................................................. 88

Figure 4. 10 General control scheme of PV inverter ............................................................. 89

Figure 4. 11 Typical LS-PVPP layout including power plant control scheme [28] ................. 93

Figure 4. 12 Voltage control function [28] ............................................................................. 94

Figure 5. 1 V-I and V-P characteristic curves of PV module at T = 25oC and G = 1000 W/m2

............................................................................................................................................. 97

Figure 5. 2 V-I and V-P characteristic curves of two (2) PV arrays ....................................... 97

Figure 5. 3 PV arrays characteristics in function of working temperature (T) ........................ 99

Figure 5. 4 PV arrays characteristics in function of irradiance (G) ........................................ 99

Figure 5. 5 Max PV power in function of temperature (T) and ............................................ 100

Figure 5. 6 Max PV power in function of irradiance (G) and ............................................... 100

Figure 5. 7 The layout of PV inverter model ...................................................................... 102


Figure 5. 8 The layout of PV plant simulation model .......................................................... 105

Figure 6. 1 PV power in function of working temperature (T) and ....................................... 107

Figure 6. 2 PV power in function of irradiance (G) and ....................................................... 107

Figure 6. 3 Option 1 in active power setpoint mode ............................................................ 109

Figure 6. 4 Option 2 in active power setpoint mode ............................................................ 110

Figure 6. 5 Response to voltage control function ................................................................ 113

Figure 6. 6 Response to voltage control function with different parameters ....................... 114

Figure 6. 7 Response to maximum allowable reactive power setpoint ............................... 116

Figure 6. 8 Response to minimum allowable reactive power setpoint ................................ 117

Figure 6. 9 Response to maximum allowable power factor setpoint ................................... 118

Figure 6. 10 Response to minimum allowable power factor setpoint .................................. 119


List of Tables

Table 2. 1 International grid codes under study .................................................................... 27

Table 2. 2 Range of normal operating frequency ................................................................. 36

Table 2. 3 Range of normal operating voltage ...................................................................... 36

Table 2. 4 Active power and frequency support requirements .............................................. 36

Table 2. 5 Parameter in case 1 ............................................................................................ 37

Table 2. 6 Parameter in case 2 ............................................................................................ 38

Table 2. 7 Constraint functions ............................................................................................. 38

Table 2. 8 Reactive power and voltage support requirements .............................................. 39

Table 2. 9 Parameters in voltage control function................................................................. 39

Table 2. 10 Fault-ride-through requirement .......................................................................... 40

Table 2. 11 Parameters in LVRT requirement ...................................................................... 40

Table 2. 12 Parameters in HVRT requirement ..................................................................... 40

Table 2. 13 Parameters in reactive current injection requirement ......................................... 41

Table 2. 14 The scope of the latest Germany´s regulation for grid code .............................. 41

Table 2. 15 The range of normal operating frequency .......................................................... 42

Table 2. 16 The range of normal operating voltage .............................................................. 42

Table 2. 17 Active power and frequency support requirements ............................................ 42

Table 2. 18 Parameters in frequency response or control .................................................... 43

Table 2. 19 Constraint functions ........................................................................................... 44

Table 2. 20 Reactive power and voltage support requirement ............................................. 44

Table 2. 21 Parameters in voltage control function............................................................... 44

Table 2. 22 Parameters in reactive power control ................................................................ 45



Table 2. 24 Voltage level and nominal output power for each type of power plants ............. 47

Table 2. 25 Nominal voltage, minimum voltage (Umin) and maximum voltage (Umax) ............ 48




Table 2. 29 Reactive power and voltage support requirements ............................................ 50


Table 2. 31 Parameters in automatic power factor control function ...................................... 52


Table 2. 33 Capacity range .................................................................................................. 53

Table 2. 34 Range of normal operating frequency ............................................................... 55






Table 2. 40 Parameters in LVRT .......................................................................................... 58

Table 2. 41 Classification based on type and voltage level at PCC ...................................... 59

Table 2. 42 Normal operating frequency .............................................................................. 60

Table 2. 43 Normal operating voltage .................................................................................. 61

Table 2. 44 Active power and frequency support requirement ............................................. 62



Table 2. 46 FRT requirement ............................................................................................... 62

Table 3. 1 Electrically Synchronous Area ............................................................................. 66

Table 3. 2 Regulation and grid code under study ................................................................. 67

Table 3. 3 The scope of regulation for grid code .................................................................. 67

Table 3. 4 Range of normal operating frequency ................................................................. 68

Table 3. 5 Range of normal operating voltage ...................................................................... 68

Table 3. 6 Active power and frequency requirement ............................................................ 68

Table 3. 7 Reactive power and voltage support requirements .............................................. 69

Table 3. 8 Parameters in reactive power control .................................................................. 69

Table 3. 9 Fault-ride-through requirement ............................................................................ 70

Table 3. 10 The geographic condition of Indonesia [49] ....................................................... 70

Table 3. 11 The geographic condition of Puerto Rico [50] .................................................... 70

Table 3. 12 The geographic condition of Denmark [51] ........................................................ 71

Table 3. 13 The geographic condition of Germany [52] ........................................................ 71

Table 3. 14 The geographic condition of European Union [53] ............................................. 71

Table 3. 15 Solar power percentage in electricity generation ............................................... 72

Table 3. 16 Status of Indonesia´s electricity interconnection system [46] [47] ...................... 72

Table 3. 17 Status of Puerto Rico´s electricity interconnection system [54] .......................... 72

Table 3. 18 Status of Denmark´s electricity interconnection system [55] [56] ....................... 72

Table 3. 19 Status of Germany´s electricity interconnection system [56] .............................. 73

Table 3. 20 Status of EU´s electricity interconnection system [56] ....................................... 73

Table 3. 21 Normal operating frequency for major islands ................................................... 73


Table 3. 22 Normal operating frequency for minor islands ................................................... 74

Table 3. 23 Normal operating voltatge for small islands ....................................................... 74


Table 3. 25 Parameters in frequency response or control for major islands and small islands

............................................................................................................................................. 76

Table 3. 26 Types of constraint functions ............................................................................. 76

Table 3. 27 Reactive power and voltage support for solar PVPP in major islands and small

islands .................................................................................................................................. 77

Table 3. 28 Parameters in voltage control function ............................................................... 77



Table 3. 32 Parameters in LVRT requirement ...................................................................... 79

Table 3. 33 Parameters in HVRT requirement ..................................................................... 80

Table 3. 34 Parameters in reactive current injection requirement ......................................... 80

Table 5. 1 Characteristics of PV module [71] ....................................................................... 95

Table 5. 2 Simulation results of PV module .......................................................................... 98

Table 5. 3 Simulation results of two (2) PV arrays ................................................................ 98

Table 5. 4 Characteristics of PV inverter model.................................................................. 103

Table 5. 5 Equivalent grid data ........................................................................................... 105

Table 6. 1 Maximum PV power in function of working temperature (T) and at constant

irradiance (G) of 1000 W/m2 ............................................................................................... 108

Table 6. 2 Maximum PV power in function of irradiance (G) and at constant working

temperature (T) of 1000 W/m2 ............................................................................................ 108


Table 6. 3 Parameters in response to voltage control function ........................................... 113

Table 6. 4 Parameters in determinate points for each period ............................................. 114

Table 6. 5 Parameters in response to another voltage control function .............................. 115

Table 6. 6 Parameters in determinate points for each period ............................................. 115



Thesis Outline

Objectives

The main objective of this master thesis is to propose grid code design or update existing grid

codes for 1 MW solar photovoltaics power plant (PVPP) connected to medium voltage (MV)

level network in Indonesia. The following tasks are carried out to attain this objective:

• Study some sets of international grid code such as grid codes of Puerto Rico, Germany,

Denmark and European Union which permits to analyze the correct trends of

connection requirement.

• Describe the existing structure of electricity transmission and distribution system as

well as current grid code of Indonesia. Then propose grid code design or update on the

existing grid code.

• Discuss the introduction and characteristics of solar PVPP that contains the basic

electrical components, inverter topologies as well as internal collection grid

configuration.

• Model and simulate a 1 MW solar PVPP together with associated devices to test the

proposed grid code design for solar PVPP in Indonesia in terms of active power

regulation (absolute production) and reactive power regulation.

Scope

The scope of study in this master thesis are.

• The grid code in this master thesis is presented from operational perspective. It

basically consists of requirement of voltage and frequency boundaries, active power

and frequency support, reactive power and voltage support and fault-ride-through

(FRT) for 1 MW solar PVPP connected to medium voltage (MV) network. In other

words, grid codes pertaining to low voltage (LV) network is out of scope of this master

thesis.

• In order to test the proposed grid code, a simplified 1 MW solar PVPP with its

associated devices is modelled and simulated in Matlab and Simulink.

Organization

This master thesis is organized as follows.

• Chapter 1: introduction to the recent developments of renewable energy sources

worldwide including solar power is described along with objectives and scopes of this

master thesis.


• Chapter 2: this chapter begins with the necessity of grid code for solar PVPP. In

addition, some international grid codes such as grid code of Puerto Rico, Germany,

Denmark and European Union are discussed. In the end of this chapter, the summary

of operational requirements such as voltage and frequency boundaries, active power

and frequency support, reactive power and voltage support and fault-ride-through of

each international grid code is given

• Chapter 3: here, the general structure of electrical generation, transmission and

distribution system in Indonesia as well as the existing grid code of Indonesia for solar

PVPP are discussed. Also, the proposed update on existing grid code for solar PVPP

is described.

• Chapter 4: an introduction of solar PVPP is given along with characteristics, basic

electrical components (i.e. photovoltaics (PV) arrays, PV inverters and transformer)

and inverter topologies together with collection grid configuration of solar PVPP.

Additionally, the control theory of solar PVPP is described in the present chapter.

• Chapter 5: in this chapter, the modelling approach for each electrical element in solar

PVPP is described. Then the model of each electrical element is simulated.

Additionally, a 1 MW solar photovoltaics power plant is modelled and simulated. The

model is made up of solar PV arrays, solar PV inverter, transformer and electrical grid.

• Chapter 6: here the results and discussion about grid code proposal for solar PVPP in

Indonesia along with the simulation result of a 1 MW solar PVPP for active power and

frequency support function particularly MPPT function as well as reactive power and

voltage support function are given.

• Chapter 7: in this chapter the conclusions of this master thesis are drawn.


Nomenclature

EU European Union

FACTS Flexible Alternating Current Transmission System

FRT Fault-Ride-Through

GHG Green House Gas

HVRT High-Voltage-Ride-Through

IEC International Electrotechnical Comission

LS-PVPP Large Scale Photovoltaics Power Plant

LV Low Voltage

LVRT Low-Voltage-Ride-Through

MV Medium Voltage

MPPT Maximum Power Point Tracking

NA Not Applicable

NS Not Stated

PCC Point of Common Coupling

PPC Power Plant Controller

PV Photovoltaics

PVPP Photovoltaics Power Plant


Introduction

Overview

It is expected that the energy demand is going to rise by 41% in the next 20 years because of

increasing industrial and residential needs [1]. In recent years, over 75% of the electricity

demand was met by using fossil fuel sources [2]. Due to its nature, fossil fuels sources cannot

be replenished in human time scale and hence it creates a need to meet the growing energy

demand using renewable energy source. Moreover, carbon dioxide (CO2) emissions from

fossil fuel combustion and industrial processes contributed approximately 78% of the total

greenhouse gas (GHG) emission increase from 1970 to 2010. Without additional efforts to

reduce GHG emissions beyond on-going efforts, emission growth is expected to continue due

to growth of economic activities and global population. It is estimated that, without additional

climate change mitigation, global mean surface temperature will increase between 3.7oC and

4.8oC in 2100 in comparison with pre-industrial level (i.e. period before 1750) [3].

In Europe, the European Union (EU) member states agreed to carry out Horizon 2020 (H2020)

plan which sets out 20% of the energy demand comes from renewable energy source, a

greenhouse gas emission reduction of 20% as well as the implementation of 20% energy

saving in a cost-efficient manner by 2020 in comparison to each respective status in 1990 [4].

In addition, Horizon (H2030) and Horizon (H2050) plan lays down the target of 27% and 75%

energy demand comes from renewable energy source, a 40% and 80% greenhouse gas

emission reduction along with the energy saving of 27% and 41% in comparison to each

respective status in 1990 [5].

Hence, renewable energy has been harnessed more and more in the recent years mainly

dominated by wind and solar energy sources. Wind power experienced the fastest growth over

the years. In fact, the aggregated wind power installation in the EU by the end of 2014 was

128.8 GW [6] whereas in Asia, US and Latin America was 115 GW [7], 65 GW [8] and 4 GW

[7] respectively.

On the contrary, PV power installations did not experience the same growth rate due to prices

of photovoltaic panels and the associated technology. According to Fraunhofer ISE, as

illustrated in Fig.1.1, the cumulative installed capacity of photovoltaics power in 2014 was

181.25 GW comprising 31.25 GW in China, 87.5 GW in Europe, 20.8 GW in North America,

25 GW in Japan, 8.3 GW in the Rest of Asia-Pacific & Central Asia, 4.2 GW in India, 2.1 GW

in Latin America & Caribbean and 2.1 GW in Middle East & Africa. By 2017 the cumulative

installed capacity of photovoltaic power rose to 414 GW (i.e. over doubled) comprising 133

GW in China, 115 GW in Europe, 58 GW in North America, 49 GW in Japan, 22 GW in the


rest of Asia-Pacific & Central Asia, 20 GW in India, 9 GW in Latin America & Carribean and 8

GW in Middle East and Africa. In 2018, USA solar market expanded by 10.6 GW of PV

especially in residential sector [10].

Figure 1. 1 Global cumulative PV installation in 2014 and 2017 [9]

The dramatic increase of variable renewable energy (e.g. wind and solar energy) source poses

a challenge to the electrical grid due to its stochastic nature, particularly on the transmission

and distribution level. The wind power plant and solar PVPP is expected not to behave like

wind and solar farm (only generate electrical power) but as similar to conventional power plant

(provide grid support functions) as possible [11]. Therefore, the need for creating grid codes

or updating the existing ones which set outs the grid support requirements defined at the point

of common coupling (PCC) for wind power plant and solar PVPP arises [12]. In this sense,

32%

28%

14%

12%

5%5% 2% 2%

Global Cumulative PV Installation in 2017

17%

48%

12%

14%

5% 2% 1% 1%

Global Cumulative PV Installation in 2014

China

Europe

North America

Japan

Rest of Asia-Pacific & CentralAsia

India

Latin America & Caribbean

Middle East & Africa


wind power plants triggered the grid code development followed by grid codes applied to solar

PVPP.


Review of International Grid Codes

Necessity of Grid Code

Generally, a power plant can be defined as a centralized system with the objective of injecting

power to the electrical grid (i.e. not to a particular individual customer) [13]. Its main goals are

to operate independently and to meet the requirements of electrical system under some

regulations. These regulations are in the forms of grid codes and standards that define

connection requirements on the MV and LV level for these power plants to the transmission

and distribution grid with purpose of increasing its reliability, stability and security. These grid

codes were traditionally established to allow interconnection of non-renewable energy power

plants to the grid. The contribution of renewable energy power plants to electricity generation

was initially very low in comparison with non-renewable energy power plants. However, this

situation started to change dramatically in the recent years due to renewable energy sources

have been harnessed more and more. As a result, in most countries, the share of renewable

energy in electricity generation increased [12].

A couple of years ago, particularly in 2014, Puerto Rico’s electricity generation came from 19.1

TWh fossil fuel energy, 0.4 TWh controllable renewable energy (i.e. any other renewable

energy than wind and solar) and 0.48 TWh variable renewable energy (i.e. wind and solar) as

illustrated in Fig. 2.1. It is seen that the in 2014 variable renewable energy source held nearly

0% of the Puerto Rico’s electricity generation [14]. However, in 2017 variable renewable

energy source emerged in Puerto Rico’s electricity generation up to 0.336 TWh (i.e. 2% of

Puerto Rico’s electricity generation) and the rest of Puerto Rico’s electricity generation was

composed of 20.58 TWh fossil fuel energy and 0.084 TWh controllable renewable energy. The

reduction of controllable renewable energy fraction is presumed to be caused by disaster of

Hurricanes Maria and Irma that destroyed much of the electricity generating facilities in 2017

[15]. However, according to Puerto Rico’s energy road map, renewable energy fraction of

Puerto Rico’s electricity generation is expected to reach 15% and 20% by 2025 and 2035,

respectively [14].

On the other side of the world, as seen in Fig.2.2, in 2010 Germany´s electricity generation

came from 352 TWh fossil fuel energy, 193.23 TWh controllable renewable energy, 49.5 TWh

variable renewable energy (i.e. wind and solar) and 37.5 TWh others [16]. It is seen that

variable renewable energy source held 7% of Germany’s electricity generation in 2010. In 2017

the share of variable renewable energy in Germany´s electricity generation increased to 67

TWh (i.e. 10% of Germany’s electricity generation) and the rest of Germany’s electricity

generation came from 328 TWh fossil fuel energy, 224 TWh controllable renewable energy

and 30 TWh others [17].


As illustrated in Fig. 2.3, the same situation happened in Denmark where in 2010

Denmark´s electricity generation came from 5.42 TWh controllable renewable energy, 7.81

TWh variable renewable energy and 25.7 TWh fossil fuel energy. It can be observed that in

2010 the variable renewable energy source held 20% of the electricity generation in

Denmark. Then in 2016 the fraction of variable renewable energy in Denmark’s electricity

generation increased drastically to 13.5 TWh (i.e. 44% of Denmark’s electricity generation)

along with the controllable renewable energy and fossil fuel energy that contributed 5.89

TWh and 11.4 TWh, respectively [18].

Generally, such a situation happened across Europe as depicted in Fig. 2.4 where in 2000,

overall EU’s electricity generation came from 1,628 TWh fossil fuel energy, 1,382 TWh

controllable renewable energy, 22.1 TWh variable renewable energy and 1 TWh others. It is

seen that in 2000, variable renewable energy source held 1% of the EU´s electricity

generation. In contrast, in 2016 the variable renewable energy source contributed 407 TWh

(i.e. 12%) of the overall EU’s electricity generation and the rest of EU’s electricity generation

came from 1,402 TWh fossil fuel energy, 1,439 TWh controllable renewable energy and 5 TWh

from the other as described in Fig.2.5 [19].

Figure 2. 1 Puerto Rico’s electricity generation mix in 2014 and 2017 [14] [15]


Figure 2. 2 Germany’s electricity generation mix in 2010 and 2017 [16] [17]

Figure 2. 3 Denmark` electricity generation mix in 2010 and 2016 [18]


Figure 2. 4 EU’s electricity generation mix in 2000 and 2016 [19]

The growing share of renewable energy in global electricity generation, especially in Europe,

is aligned with the increasing share of installed power capacity in Europe. In the last decade,

approximately 60% newly constructed power generation is of variable renewable energy

generation. As depicted in Fig.2.5, in 2005, the variable renewable energy power generation

accounted for 43 GW (i.e. 6%) of the EU´s installed power capacity. Then, the rest is made up

of fossil fuel power generation, controllable renewable energy power generation, variable

renewable energy power generation and the other type of power generation accounted for 357

GW, 258 GW and 18 GW, respectively. In 2017, the share of variable renewable energy

generation rose to 276 GW (i.e. 29%) of the EU´s installed power capacity and the rest is made

up of 365 GW fossil fuel power generation, 270 GW controllable power generation and 27 GW

other type of power generation [20].


Figure 2. 5 EU´s installed power capacity in 2005 and 2017 [20]

By nature, renewable energy source, particularly variable renewable energy source (i.e. wind

and solar photovoltaics) entails intermittency which present problems to the electrical system.

These problems can be overcome by the provision of grid support function of the variable

renewable energy power generation. The grid support requirement for variable renewable

energy power plant is set out in grid codes and standards established by relevant system

operator. Therefore, it is necessary to review and update the grid code and standard regularly

as the amount of variable renewable energy penetration is growing.

The other motivation for establishment of grid codes and standards is that before the

privatization and liberation of electricity market, the electricity network of generation,

transmission and distribution could be managed by the same company. After the privatization

and liberalization of electricity market that leads to deregulation, different companies may

manage each network of transmission and distribution. Consequently, responsible system

operators worldwide have prepared grid codes and standards that set out the technical

specifications and operational characteristics at the point of connection that power generation

must comply. It has the purpose of maintaining uniformity of requirements for each power

generation. These grid codes vary by local regulation, legal and technical environment.

In this way, wind power plants first triggered the development of grid codes followed by solar

PVPP. According to the electricity system operator of the UK, grid code is the technical code

for connection and development of the National Electricity Transmission System (NETS) [21].

Additionally, grid code can be defined as a technical document containing the set of rules

governs the operation, maintenance and development of the system at the point of common


coupling (PCC) [22].

Thus, this chapter is dedicated for discussion about international grid codes for solar PVPP in

selected countries (i.e. Puerto Rico, Germany, Denmark and European Union) since they have

common trend of growing share of solar PVPP in their individual installed power capacity.

Moreover, their grid codes are mature enough and well-defined to study. Then, an analysis of

the main grid code requirements for solar PVPP connected to the electrical system is

performed. This analysis is carried out from viewpoint of frequency and voltage boundaries,

active power and frequency control, reactive power and voltage control along with fault-ride-

through capability.

In following sections, as described in Table. 2.1, each set of grid codes of Germany, Denmark,

Puerto Rico and European Union for LS-PVPP connected to medium voltage network

managed by relevant system operator in respective country is discussed.

Country /

Territory

Organization Title Version

USA

(Puerto Rico)

PREPA Technical Requirements for

Interconnecting Wind and Solar

Generation

August, 2012

Germany VDE Summary of the Draft VDE-AR-N

4110:2017:02 – Connection and

Operation to Medium Voltage Grid

February, 2017

Denmark Energinet Technical Regulation 3.2.2. for PV

Power Plants Above 11 kW

July, 2016

European Union European

Comission

EU Directive 2016/631

Establishing a Network Code on

Requirements for Grid Connection

Generators

April, 2016

Table 2. 1 International grid codes under study

Contents of Grid Code

In this section, the basic contents of grid code from operational viewpoint are discussed. The

first regulations that established the connection requirement for solar PVPP to the electrical


network are IEEE 1547 and EN 50160. They are intended for small scale solar PVPPs

interconnected to the distribution network for residential, commercial and industrial purpose.

In fact, these regulations prevented small scale solar PVPPs from providing ancillary services

such as frequency and voltage support as well as reactive power support [23]. However, as

discussed earlier, in the coming years the large amount of solar power is expected to penetrate

into the electrical grid. This may cause problems due to its intermittency, lack of voltage

support, variable active power and power mismatching. Therefore, the grid codes for

interconnection of solar PVPP to the electrical network have been developed in a way that

capability of fault-ride-through, active power and frequency support along with reactive power

and voltage support is required.

Germany is the first country that launched grid codes for solar PVPP connected to MV and HV

level network in 2008 [22]. 4 years after Denmark´s grid code for wind power plant was

released. This grid code has been an inspiration for the other grid codes by several other

countries in Europe. After Germany´s grid code, South Africa [24], China [25] and Romania

[26]

Grid code from operational perspectives basically contains voltage and frequency boundaries,

active power and frequency control function, voltage and reactive power control function, and

FRT capability and they are summarized one by one in following subsections.

Voltage and Frequency Boundaries

Grid code essentially states the electrical boundaries under which the solar PVPP must

operate continuously. The electrical boundaries consist of range of normal operating voltage

and frequency at the PCC. Each range consists of several sub-ranges in which the solar PVPP

must remain online for particular period of time. The voltage and frequency boundaries are

established uniformly by relevant system operator for each solar PVPP.

Active Power and Frequency Control Functions

As the solar energy varies throughout the day, the need for controlling the active power of solar

PVPP arises. Active power and frequency control is essentially made up of function of

frequency response or control, absolute production (i.e. power curtailment), delta production

(i.e. power reserve) and power gradient (i.e. ramp rate). Frequency response or frequency

control can be defined as the capability of a solar PVPP to adjust its active power output (P) in

response to a measured deviation at the point of common coupling of system frequency (Δf)

from a setpoint with a view to stabilize the grid. The permissible variation of active power due

to the change of frequency is described by droop. Droop constant is expressed by the ratio of

change in frequency (Δf) over nominal frequency (fn) to change of actual active power output

(ΔP) over nominal output power (Pn) or actual active power output (Pac) depending on the grid


code. The frequency response or control is illustrated in Fig.2.6. The frequency response or

control is composed of upward droop (line from f2 to f1), dead band (the range where no change

in active power), downward droop (line from f3 to fmax) and control band (the range comprises

upward droop, dead band and downward droop). In addition, the active power output is allowed

to rise again after the frequency f4 is reached. Please note that fn represents nominal

frequency.

Absolute production is the adjustment of active power (P) to maximum level at the point of

common coupling as indicated by setpoint. The purpose of absolute production is to protect

the electrical grid from overloading in critical situations. Then, delta production is the power

reserve that a solar PVPP creates out of the difference between the available active power

output (Pav) and actual active power output (Pac). The purpose of delta production is to establish

a regulating reserve for upward regulation related to the delivery of ancillary service (i.e.

frequency response or control). In addition, power gradient is used to limit the maximum speed

by which the active power (ΔP) can be changed in the event of changes in power or the set

points for a plant. Its unit is power over time. The purpose of power gradient is to prevent the

changes in active power from adversely impacting the electrical grid. Fig.2.7. Illustrates the

function of absolute production, delta production and power gradient.

Figure 2. 6 Frequency response or control [adapted from [12]]


Figure 2. 7 Absolute production, delta production and power gradient [adapted from [27]]

Reactive Power and Voltage Control Functions

Solar PVPP must be capable of overcoming voltage deviations and providing reactive

support to the grid as conventional power plants. Thus, grid codes establish the minimum

reactive power requirement that solar PVPP must comply with. In the past, PV inverters

were not designed considering this requirement but recently some PV inverter

manufacturers considering this requirement in PV inverters specification. The capability of

reactive support in PV inverters varies in function of the solar irradiance and temperature.

To accommodate the connection of solar PVPP to the electrical network and collaborate

smoothly, the relevant system operator encounters two challenges: (1) the voltage has to

be kept inside within the dead band regulated by relevant system operator. (2) the solar

PVPP must follow the capability curve given by the relevant system operator that defines

the relation between reactive and active power [12].

There are four methods to regulate the reactive power and voltage: (1) voltage (V) control, (2)

power factor (PF) control, (3) automatic power factor (PF) control and (4) reactive power (Q)

control. Voltage control regulates the voltage based on the droop function that is defined as

the ratio of variation of voltage (ΔV) over nominal voltage (Vn) due to the change of reactive

power (ΔQ) over instantaneous power (actual power (Pac) in case no delta production) as

illustrated in Fig.2.8. The power factor control regulates the reactive power (Q) based on the

value of active power (P) whereas automatic power factor (PF) control regulates the reactive

power with a variable PF depending on the generated active power as illustrated in Fig.2.9.

When the ratio of actual power (Pac) to available power (Pav) reaches X1 then the solar PVPP

starts supplying reactive power (Q) following a linear gradient until it reaches power factor (PF)


of 1. And the last method is reactive power control that regulates directly the reactive power

(Q) at the PCC. The solar PVPP must be capable of regulating the reactive power and voltage

using any of these controls. The most commonly used functions are combination of voltage

control and reactive power control as well as voltage control and power factor control.

However, in some grid code the reactive power control, power factor control and voltage

control are mutually exclusive which implies that only one of the three functions can be

performed at a time [27]. Fig.2.10 depicts normal operating zones of solar PVPP as functions

of power factor (PF) and reactive power (Q). There are two types of operating zones: (1)

rectangular-shaped zone in which solar PVPP must be capable of providing reactive power

between Q1 and Q2 with no regard to power factor (2) triangle-shaped zone in which solar

PVPP must be capable of providing reactive power between Q1 and Q2 with regard to power

factor in the range of PF1 and PF2. Additionally, in some international grid codes, below

particular active power (P1) solar PVPP is not required to deliver reactive power (Q).

Figure 2. 8 Voltage control with droop function [adapted from [28]]


Figure 2. 9 Automatic power factor control [adapted from [27]]

Figure 2. 10 Normal operating zones as functions of power factor and reactive power

[adapted from [12]]

Fault-Ride-Through (FRT) Capability

Fault-ride-through (FRT) capability is a capability normally possessed by solar PVPP to

remain online in the event of symmetrical and/or asymmetrical fault. FRT capability is


composed of low-voltage-ride-through (LVRT) capability and high-voltage-ride-through

(HVRT) capability along with reactive current injection (Iq) capability.

Low-voltage-ride-through (LVRT) capability is a capability by which solar PVPP remains

online in undervoltage situation for certain period of time. This capability is illustrated in

Fig.2.11. In case of the normal voltage profile at the PCC (i.e. in zone A) the solar PVPP

must remain online continuously whereas in case of voltage profile is located in zone B the

solar PVPP must remain online for certain period of time and perform reactive current

injection to help stabilizing the network. In addition, the solar PVPP is not required to remain

online in case the voltage profile is located in zone C.

High-voltage-ride-through (HVRT) capability is a capability by which solar PVPP remain

online in overvoltage situation for certain period of time. This capability is required in several

international grid codes. Fig.2.12 depicts this capability. In case the voltage profile at the

PCC is located in zone A then the solar PVPP must stay connected to the network

continuously. In contrast, in case the voltage profile is located in zone B then the solar PVPP

must remain online for determinate periods of time. Additionally, in case the voltage profile

is located in zone C then the solar PVPP is not required to remain online.

Figure 2. 11 LVRT Capability [12]


Figure 2. 12 HVRT capability [12]

Besides LVRT capability and HVRT capability, reactive current injection capability is required

in undervoltage situation in several international grid codes. This requirement defines the

reactive current injection in function of voltage as shown in Fig.2.13. This capability essentially

consists of deadband (i.e. a range without reactive current injection), droop constant (i.e. ratio

of change of reactive current (ΔIq) over nominal current (Iq) to change of voltage (ΔV) over

nominal voltage (Vn), voltage deviation setpoint 1 (X1) where solar PVPP begin injecting 100%

reactive current as well as the voltage deviation setpoint 2 (X2) where the solar PVPP start

absorbing 100% reactive current.


Figure 2. 13 Reactive current injection

Grid Codes of Puerto Rico

2.3.1 Voltage and Frequency Boundaries

According to the latest regulation of Puerto Rico, the range of normal operating frequency

along with minimum duration to remain online of a solar PVPP and the range of normal voltage

are listed in Table 2.2 and Table 2.3, respectively.

Nominal Frequency,

fn (Hz)

Range of Normal

Operating Frequency

(Hz)

Minimum Duration

60

x<56.5 Instantaneous trip

56.5≤x<57.5 10 sec


57.5≤x≤61.5 Continuous

61.5<x≤62.5 30 sec

x>62.5 Instantaneous trip

Table 2. 2 Range of normal operating frequency

Range of Normal

Operating Voltage (pu)

Minimum Duration

0.85-1.15 Continuous

Table 2. 3 Range of normal operating voltage

2.3.2 Active Power and Frequency Support

Table 2.4 outlines the active power and frequency support requirements for solar PVPP.

Requirements for a 1 MW solar PVPP Response

Frequency response or control. frequency

response or control is detailed below

Yes

Absolute production. absolute production or

power curtailment is detailed below

Yes

Delta production. delta production or power

reserve is detailed below

Yes

Power gradient. power gradient or ramp rate or

is detailed below

Yes

Table 2. 4 Active power and frequency support requirements

Frequency Response

In the latest Puerto Rico´s grid code, there are two cases in regards to frequency response or

control.

(1) For small frequency deviations (i.e. less than 0.3 Hz), the parameters illustrated in

Fig.2.6 are listed in Table 2.5.


Parameter Value

fmin 56.5 Hz

f1 ≥59.694 Hz

f2 59.994 Hz

f3 60.006 Hz

f4 ≤60.306 Hz

fmax 62.5

Upward droop constant 5% as a function of

nominal output

power (Pn)

Downward droop constant 5% as a function of

nominal output

power

Response time for both

droops

<1 s

Actual power NS

Table 2. 5 Parameter in case 1

NS : not stated

(2) For large frequency deviations (i.e. greater than 0.3 Hz), the parameters illustrated

in Fig.2.6 are illustrated in Table 2.6.

Parameter Value

fmin 56.5

f1 <59.694 Hz

f2 59.994 Hz

f3 60.006 Hz


f4 >60.306 Hz

fmax 62.5

Upward droop constant 5% a function of

nominal output power

Downward droop

constant

5% a function of



droops

<1 s

Settling time for both

droops

NS

Actual power ≥10% of nominal output

power

Table 2. 6 Parameter in case 2

Constraint Functions

The type of constraint functions is listed in Table 2.7.

Type of Constraint Functions Value

Absolute production aw-TSO

Delta production 10% nominal output power ≤ x

≤ 100% nominal output power

Ramp rate

Rate of increase of power Rate of decrease of power Rate of increase of power when an absolute production constraint turns off Rate of decrease of power when an absolute production constraint turns on

10% of nominal output power

per minute with tolerance of

10%

Table 2. 7 Constraint functions

*aw-TSO: agreed with transmission system operator


2.3.3 Reactive Power and Voltage Support

Table 2.8 summarizes the reactive power and voltage support requirements for a solar PVPP

according to the latest Puerto Rico´s regulation.


Voltage control. voltage control is detailed below Yes

Reactive power control. No

Power factor control. No

Automatic power factor control. No

Table 2. 8 Reactive power and voltage support requirements

Voltage Control

Table 2.9 illustrates parameters with regards to voltage control function as depicted in Fig.2.8.

Parameters Value

Deadband 0.999pu≤x≤1.001pu

Upward droop function 0%<x≤10%

Downward droop function 0%<x≤10%

Time response 1s for 95% total reactive power

Upper limit of reactive power

delivery

0.62 of actual active power (Pac)

Lower limit of reactive power

delivery

-0.62 of actual active power (Pac)

Table 2. 9 Parameters in voltage control function

2.3.4 Fault-Ride-Through Requirement

Table 2. 10 lists the requirement of FRT for a 1 MW solar PVPP.



LVRT capability due to symmetrical and

asymmetrical fault

Yes

HVRT capability due to symmetrical and

asymmetrical fault

Yes

Reactive current injection Yes

Table 2. 10 Fault-ride-through requirement

Table 2.11 explains the parameters in LVRT requirement described in Fig.2.11.

Parameters Value

V1 0

V2 0.1 pu

V3 0.85 pu

t1 600 ms

t2 3 s

Table 2. 11 Parameters in LVRT requirement

In addition, Table 2.12 describes the parameters with regards to high-voltage-ride-through

requirement depicted in Fig. 2.12.

Parameters Value

V1 1.4 pu

V2 1.3 pu

V3 1.15 pu

t1 150 ms

t2 1 s

t3 3 s

Table 2. 12 Parameters in HVRT requirement


During undervoltage fault condition, solar PVPP must operate on reactive current injection

mode as parameters listed in Table 2.13 and depicted in Fig.2.13.

Parameters Value

Droop constant 1%≤x≤5%

Deadband 15%

X1 aw-TSO

X2 NS

Table 2. 13 Parameters in reactive current injection requirement


NS: not stated

Grid Codes of Germany

The latest regulation of Germany for grid codes for power plants connected to MV level

network is based on that for HV level network. The scope of this regulation is explained in

Table 2.14.

Parameter Value

Grid Voltage (kV) [29] 1-60

Type of Power Generation

[30]

Type 1 – power generation with synchronous generation and its associated storage

Type 2 – power generation with asynchronous generator and its associated storage

Typical Size of Power Generation [31]

500 kW to 100 MW

Table 2. 14 The scope of the latest Germany´s regulation for grid code

In this section the requirements for type 2 is focused since in this master thesis, emphasis is put on a 1 MW solar PVPP.


The range of normal frequency and voltage for solar PVPP connected to MV level network

is described in Table 2. 15 and Table 2. 16, respectively [29].

Nominal Frequency (Hz)

Range of Normal Operating Frequency (Hz)

Minimum Duration

50 x<47.5 Instantaneous trip

47.5≤x<49 30 minutes


49≤x≤51 Continuous

51<x≤51.5 30 minutes


Table 2. 15 The range of normal operating frequency

Range of Normal Operating Voltage (pu)

Minimum Duration


0.85≤x<0.9 60 seconds


1.1<x≤1.15 60 seconds


Table 2. 16 The range of normal operating voltage

Normal operation is defined as the condition where voltage gradient is less than 5% per

minute and frequency gradient is less than 0.5% per minute. In addition, voltage gradients

over 5% is acceptable in the voltage range of 0.9 pu - 1.1 pu.


Table 2. 17 outlines active power and frequency support requirement.

Requirements for a 1 MW Solar PVPP Response


response or control is specified below

Yes



Yes



Yes

Power gradient. power gradient or ramp rate or

is detailed below

Yes


Frequency Response

The relevant parameters in frequency response or control function depicted in Figure 2. 6 is

listed in Table 2. 18.


Parameter Value

fmin 47.5 Hz

f1 48.8 Hz

f2 49.8 Hz

f3 50.2 Hz

f4 50.1 Hz

fmax 51.5 Hz

Upward droop constant 5% as a function

of nominal

output power

(Pn)

Downward droop constant 5% as a function

of actual output

power (Pn)


droops

2 s


droops

20 s

Actual power NS

Table 2. 18 Parameters in frequency response or control


Table 2. 19 describes the types of available constraint function.



Delta production aw-TSO


Ramp rate


19.8% of nominal output power

per minute ≤ x ≤39.6% of

nominal output power per

minute



Table 2. 20 summarizes reactive power and voltage support requirement for solar PVPP.


Voltage control. voltage control is detailed below Yes

Reactive power control. reactive power control is detailed below Yes

Power factor control. power factor control is detailed below Yes


Table 2. 20 Reactive power and voltage support requirement

Voltage Control

Table 2. 21 illustrates parameters with regards to voltage control function as depicted in Figure

2. 8.

Parameters Value

Deadband NA

Upward droop function 0%<x≤8.333%

Downward droop function 0%<x≤8.333%

Ramp rate aw-TSO


*NA : not applicable


Reactive Power Control

Solar PVPP must be capable of providing the reactive power from Q1 to Q2 with regard to the

power factor between PF1 to PF2 (i.e. zone 2). In fact, solar PVPP is not required to supply

reactive power below determinate active power (P1). Table 2. 22 establishes the parameters

illustrated in Figure 2. 10.

Parameters Value (pu)

PF1 0.9

PF2 -0.9

Q1 0.48

Q2 -0.48

P1 0.05

Time Response NS

Table 2. 22 Parameters in reactive power control

Power Factor Control

Solar PVPP must be capable of delivering reactive power as a function of active power. As

listed in Table 2. 22, solar PVPP must be capable of operating at power factor between PF1

and PF2 depicted in Figure 2. 10.

2.4.4 Fault-Ride-Through Capability

Table 2. 23 outlines the FRT requirement.



asymmetrical fault

Yes


asymmetrical fault

Yes




Figure 2. 14 FRT requirement [adapted from [29]]

Figure 2. 14 depicts FRT requirement comprising HVRT for both symmetrical and

asymmetrical fault as well as LVRT for individual symmetrical and asymmetrical fault. The

criteria for fault start are voltage at PCC ≥ 1.1 of nominal voltage (Un) or ≤ 0.9 Un. Furthermore,

the criteria for fault end is 5 s after the fault starts and all line-to-line voltages should be restored

in the range between 0.9 Un and 1.1 Un.

For reactive current injection requirement, it is set out in the latest grid code of Germany.

However, its value is not explicitly specified.

Grid Codes of Denmark

Denmark’s regulations classify power plants based on the voltage at the PCC and nominal

output power (i.e. active power) into 5 types. Table 2. 24 lists the voltage level and nominal

output power for each type of power plants.


Parameters Type A1 Type A2 Type B Type C Type D

Rated power x ≤11 kW 11 kW < x ≤

50kW

50 kW < x ≤

1.5 MW

1.5 MW < x ≤

25 MW

x>25 MW

Voltage level x≤100 kV x≤100 kV x≤100 kV x≤100 kV x>100 kV

Table 2. 24 Voltage level and nominal output power for each type of power plants

Moreover, the Denmark’s regulations are made up of five technical regulation according to the

nature of power plant as follows.

• The first technical regulation applies to all generation plants (excluding battery plants) that

are up to and including 11 kW [32].

• The second technical regulation applies to connection requirement pertaining to solar

PVPP over 11 kW [27].

• The third technical regulation describes connection requirement for thermal power plants

over 11 kW [33].

• The fourth regulation defines the connection requirement for wind power plants above 11

kW [34].

• The fifth regulation details the connection requirement for battery plants [35].

In this section, the second technical regulation that defines that connection requirement for

power plants type B is more focused since this master thesis deals with a 1 MW solar PVPP.


The range of normal operating voltage at the PCC is Un±10% and the nominal frequency is 50

Hz as well as the range of normal operating frequency is from 47.00 Hz to 52.00 Hz in which

the solar PVPP must remain connected to public electricity grid.

The range of normal operating voltage is derived from nominal voltage (Un) as listed in Table

2. 25. The operating voltage should lie between the minimum (Umin) and maximum voltage

(Umax) listed in Table 2. 25.

Voltage Level

Descriptions

Nominal Voltage

Un [kV]

Minimum Voltage

Umin [kV]

Maximum

Voltage


Umax [kV]

High voltage

[HV]

60 54 72.5

50 45 60

Medium voltage

[MV]

33 30 36

30 27 36

20 18 24

15 13.5 13.5

10 9 12

Low voltage

[LV]

0.69 0.62 0.76

0.4 0.36 0.44

Table 2. 25 Nominal voltage, minimum voltage (Umin) and maximum voltage (Umax)


Table 2. 26 outlines the active power and frequency support requirements.




Yes



Yes

Delta production. No

Power gradient. power gradient or ramp rate is

detailed below

Yes



Frequency Response

The relevant parameters in frequency response or control function described in Figure 2. 6 is

listed in Table 2. 27.

Parameter Major Islands

fmin 47.0 Hz

f1 NA

f2 NA

f3 50.0-52.0 Hz

(aw-TSO)

50.2 Hz

(standard value)

f4 NA

fmax 52.0 Hz

Upward droop constant NA

Downward droop constant 2-12%

(aw-TSO)

4% as a function

of actual output

power

(standard value)

Response time for

downward droop

2 s

Settling time for downward

droop

15 s

Actual power NA




Table 2. 28 describes the constraint functions stated in the technical regulation.



Delta production NA

Ramp rate


100 kW/s


The response and settling time for both absolute production and ramp rate constraints are 2

seconds and 10 seconds, respectively.


Table 2. 29 lists the reactive power and voltage support requirements. In fact, the control

functions of voltage control, reactive power control and power factor control are mutually

exclusive, meaning only one of the three functions can be activated at a time.

Requirement for a 1 MW solar PVPP Response

Voltage control No

Reactive power control*. reactive power control is detailed below Yes

Power factor control*. power factor control is detailed below Yes

Automatic power factor control*. automatic power factor control is detailed

below

Yes



Nb : *reactive power control, power factor control and automatic power factor control must not

be performed in the absence of agreement with transmission system operator


Solar PVPP is responsible of providing the reactive power from Q1 to Q2 with regard to the

power factor between PF1 to PF2 (i.e. zone 2). Table 2. 30 establishes the parameters



PF1 0.9

PF2 -0.9

Q1 0.48

Q2 -0.48

P1 NA

Time response (100% of

steady-state response)

10 s



Solar PVPP must be capable of delivering reactive power as a function of active power. As

listed in Table 2. 30, solar PVPP must be capable of operating at power factor between PF1

and PF2 depicted in Figure 2. 10. Additionally, the solar PVPP must reach power factor setpoint

by 10 s (i.e. time response of 10 s).

Automatic Power Factor Control

The activation and deactivation levels for this function are normally 105% and 100% of the

nominal voltage (Un), respectively and they both must be adjustable via setpoints. Table 2. 31

lists the parameters in automatic power factor control function depicted in Figure 2. 9.

Parameter Value


X1 0.5

Y1 0.9

Table 2. 31 Parameters in automatic power factor control function


Table 2. 32 lists the FRT requirement.

Requirement for 1 MW solar PVPP Response


asymmetrical fault

No


asymmetrical fault

No

Reactive current injection No


The FRT requirements for solar PVPP type B are not set out in the second technical regulation.

2.6 Grid Codes of European Union

In the latest grid codes of European Union, power plants are essentially classified into four

types on the basis of voltage level at PCC along with their nominal output power listed in Table

2. 33.

• Type A : the voltage level at PCC is below 110 kV and the capacity is below limit stated in Table 2. 33.

• Type B : the voltage level at PCC is below 110 kV and the capacity is located within the range defined in Table 2. 33.

• Type C : the voltage level at PCC is below 110 kV and the capacity falls within the range stated in Table 2. 33.

• Type D : the voltage level at PCC is equal to or above 110 kV or the capacity is stated within the range stated in Table 2. 33.

Synchronous

Area

Capacity Range

of Type A

Capacity Range

of Type B

Capacity Range

of Type C

Capacity Range

of Type D


Continental

Europe

x<0.8 kW 0.8 kW≤x≤1

MW

1 MW<x≤50 MW 50 MW<x≤75

MW

Great Britain x<0.8 kW 0.8 kW≤x≤1

MW

1 MW<x≤50 MW 50 MW<x≤75

MW

Nordic x<0.8 kW 0.8

kW≤x≤1.5MW

1.5 MW<x≤10 MW 10 MW<x≤30

MW

Ireland and

Northern

Ireland

x<0.8 kW 0.8

kW≤x≤0.1MW

0.1 MW<x≤5 MW 5 MW<x≤10

MW

Baltic x<0.8 kW 0.8

kW≤x≤0.5MW

0.5 MW<x≤10 MW 10 MW<x≤15

MW

Table 2. 33 Capacity range

Synchronous area is defined as an area covered by synchronously interconnected TSOs, for

instance synchronous areas of Continental Europe, Great Britain, Ireland-Northern Ireland and

Nordic along with the power system of Lithuania, Latvia and Estonia which forms Baltic

synchronous area. This is illustrated in Figure 2. 15.


Figure 2. 15 The map of synchronous areas in Europe [36]


In regards to range of normal operating voltage and frequency, the relevant solar PVPP must

be capable of remaining online and operate normally when the voltage decreases to 0.85 pu

and in ranges of normal operating frequency with minimum duration as listed in Table 2. 34.

Synchronous Area Nominal

Frequency (Hz)

Range of Normal

Operating Frequency

Minimum

Duration

European Union

(Continental

Europe)


47.5≤x<48.5 Not less than 30

minutes [a]

48.5≤x<49 Not less than

period for

47.5Hz≤x<48.5Hz

Baltic

Ireland and

Northern Ireland

Great Britain

Nordic

Continental

Europe


49≤x≤51 Unlimited




[a] : to be agreed with relevant system operator


Table 2. 35 outlines active power and frequency support requirement.


Frequency response or control.

frequency control is detailed below

Yes

Absolute production. No

Delta production. No

Power gradient.

power gradient or ramp rate is detailed below

Yes


Frequency Response or Control

In the latest grid code of European Union, the parameters in frequency response or control

function described in Figure 2. 6 is listed in Table 2. 36.

Parameter Value

fmin 47.5 Hz

f1 NS

f2 aw-TSO


f3 50.2-50.5 Hz

(aw-TSO)

f4 NA

fmax 51.5 Hz

Upward droop constant 2% as a function of


(Pn)

(in case f2 < 49 Hz)

10% as a function of


(Pn)

(in case 49 Hz < f2 <

49.5 Hz

Downward droop constant 2-12% as a function of

actual active power

(Pac) or nominal output

power (Pn)

(aw-TSO)

Response time for

downward droop

≤ 2 s

Settling time for downward

droop

NS

Actual power NS



Table 2. 37 describes the constraint functions.



Absolute production NA

Delta production NS

Ramp rate

Rate of increase of power

NS



Table 2.38 lists the reactive power and voltage support requirement.


Voltage control. No

Reactive power control. reactive power control is detailed below Yes

Power factor control. No




In the latest grid code of EU, reactive power control requirement is set out. However, the

provision range of reactive power and the time response are not specified.


Table 2. 39 outlines the FRT requirement.



asymmetrical fault

Yes


asymmetrical fault

No




The LVRT requirement due to symmetrical fault is depicted in Fig.2.16 below.

Figure 2. 16 LVRT requirement due to symmetrical fault

Table 2. 40 lists parameters in Fig.2.16.

Voltage Parameters (pu) Time Parameters (seconds)

V1 0.05-0.15 t1 0.14-0.25

V2 V2-0.15 t2 t1

V3 V2 t3 t2

V4 0.85 t4 1.5-3.0

Table 2. 40 Parameters in LVRT

In addition, the LVRT requirement due to asymmetrical fault must be specified by relevant TSO

on case-by-case basis. The reactive current injection requirement is set out in the latest grid

code of EU. However, its details are not specified.


2.7 Summary

In the present section, the summary of grid codes of Puerto Rico, Germany, Denmark and

European Union pertaining to 1 MW solar PVPP connected to medium voltage (MV) level

network is given from different perspectives as follows.

• Classification based on type and voltage level at PCC is listed in Table 2. 41

Country Type Voltage

Level

Lower

Limit (kV)

Upper

Limit (kV)

Puerto Rico NS NS NS NS

Germany 2 Medium

Voltage

1 60

Denmark B Medium

Voltage

- 33

European Union B for

Continental

Europe,

B for Great

Britain,

B for Nordic, C

for Ireland and

Northern

Ireland &

C for Baltic

NS - 110

Table 2. 41 Classification based on type and voltage level at PCC

• Table 2. 42 describes normal operating frequency based on each grid code

Grid code Frequency (Hz) Limits (Hz) Minimum Duration

Puerto Rico 60


56.5≤x<57.5 10 sec



61.5<x≤62.5 30 sec


Germany 50


47.5≤x<49 30 minutes


50<x≤51 30 minutes


Denmark 50

x<47 Instantaneous trip


x>52 Instantaneous trip

European Union 50

• Continental Europe


47.5≤x<48.5 Not less than 30

minutes [1]

48.5≤x<49 Not less than period

for

47.5Hz≤x<48.5Hz

49≤x≤51 Unlimited



[1] Specified by relevant system operator

Table 2. 42 Normal operating frequency

• Table 2. 43 illustrates normal operating voltage in each grid code


Grid code Range of Voltage

(pu)

Minimum Duration

Puerto Rico


0.85<x≤1.15 Continuous


Germany


0.85≤x<0.9 30 minutes


1.1<x≤1.15 30 minutes


Denmark




European Union

(Continental Europe)


x≥0.85

Continuous

Table 2. 43 Normal operating voltage

• Table 2. 44 summarizes the active power and frequency support requirement in each grid code

Requirements for 1 MW

Solar PVPP

Puerto Rico’s

regulation

Germany’s

regulation

Denmark’s

regulation

EU’s

regulation

Frequency response or

control

Yes Yes Yes Yes

Absolute production Yes Yes Yes No

Delta production Yes Yes No No


Power gradient Yes Yes Yes Yes

Table 2. 44 Active power and frequency support requirement

• Reactive power and voltage support requirement are outlined in Table 2. 45.

Requirement for 1 MW solar

PVPP

Puerto Rico’s

regulation

Germany’s

regulation

Denmark’s

regulation

EU`s

regulation

Voltage control Yes Yes No No

Reactive power control No Yes Yes Yes

Power factor control No Yes Yes No

Automatic power factor

control

No No Yes No


• FRT requirement is listed in Table 2. 46.

Requirement for 1 MW

solar PVPP

Puerto Rico’s

regulation

Germany’s

regulation

Denmark’s

regulation

EU´s

regulation

Low-voltage-ride-through

capability due to symmetrical

and asymmetrical fault

Yes Yes No Yes

High-voltage-ride-through

capability due to symmetrical

and asymmetrical fault

Yes Yes No No

Reactive current injection Yes Yes No Yes

Table 2. 46 FRT requirement


Grid Code Proposal for Solar PVPP in Indonesia

In chapter 3 the growing share of renewable energy in electricity generation and installed

power capacity in Puerto Rico and Europe is discussed. As depicted in Figure 3. 1 Indonesia´s

installed power capacityFigure 3. 1, an opposite situation happened in Indonesia where in

2009 Indonesia´s installed power capacity was made up of 4.9 GW controllable renewable

energy power generation (i.e. 16%) and 26.5 GW fossil fuel power generation [37]. Then in

2015 the share of controllable renewable energy power generation in Indonesia´s installed

power capacity increased slightly in size to 7 GW (i.e. 14%) and fossil fuel power generation

held 43 GW of Indonesia´s installed power capacity [38].

Figure 3. 1 Indonesia´s installed power capacity

in 2009 and 2015 [adapted from [37] and [38]]

However, according to Indonesia´s energy policy by 2025 the energy demand is planned to


be met by 332 TWh fossil fuel energy, 95.3 TWh controllable renewable energy (i.e. 21%) and

4.3 TWh solar (1%) and 4.3 TWh wind (1%) as illustrated in Figure 3. 2 [39].

Figure 3. 2 Indonesia´s energy mix by 2025 [39]

Recently a number of solar PVPPs came into operation in Indonesia amounts to 17.02 MW

[40] and on average each solar PVPP has capacity of 300 kW [41].

Since Indonesia´s government begun to construct a large number of solar PVPPs to follow

their energy policy and by nature solar PVPP entails intermittency, it is necessary to review

the current regulation and existing grid code of Indonesia to ensure the integration of large

amount of solar power into the grid smoothly.

3.1 Existing Electricity Transmission and Distribution System

Generally electrical power system is made up of

1. Power station

This is the place where electrical power is generated in which turbine (i.e. prime mover)

and generator in case of conventional power plant and PV array, PV inverter and LV-

MV transformer in case of solar PVPP can be found. The generated electricity has a

medium voltage level in the range of 6 kV to 24 kV with frequency of 50 Hz.

2. Electricity transmission system

Is a system whose function is to transmit electrical power from power station to electricity

distribution system.


Figure 3. 3 Illustrative single line diagram of generation, transmission and

distribution system in Indonesia [Adapted from [42]]

Figure 3. 3 illustrates the single line diagram of power generation, transmission and distribution

system. It starts with two power stations (G1 and G2) where the electricity is generated. Then

the electricity is forwarded to transmission system comprising primary and secondary

transmission substations, tie-line and transmission customer. The transmission system serves

to adjust and regulate the voltage in transmitted electricity. According to International

Electrotechnical Comission (IEC), extra high voltage is characterized by any nominal voltage

above 245 kV and high voltage is any nominal voltage in the range of 35 kV to 230 kV. Besides,

medium voltage is any nominal voltage in the range of 1 kV to 35 kV as well as low voltage is

any nominal voltage below 1 kV [43]. Indonesia’s regulation defines the voltage level in the

same manner with IEC [44]. In electric power system, long distance between power station

and load causes instability which creates the need for utilization of ancillary services such as

flexible alternating current transmission system (FACTS) or capacitor banks [45]. In electricity

transmission system, transmission substations serve to connect multiple transmission lines.

The simplest case is where all transmission lines operated at the same voltage. In such cases,

substation houses high-voltage switches that enables lines to be connected or isolated for fault

clearance or maintenance. A small substation may be a little more than a bus and several

circuit breakers. A normal size substation may houses transformer, voltage control or power

factor correction devices such as FACTS as well as phase shifting transformer to regulate

power flow between two adjacent power systems and some circuit breakers.


Indonesia’s electricity transmission system is not interconnected across the nation [46] [47]. In

fact, Indonesia is currently split into several electrically synchronous areas as listed in Table 3.

1.

No. Electrically Synchronous Area

1. Sumatra island

2. Java island, Madura Island and Bali island

Table 3. 1 Electrically Synchronous Area

While the other major islands such as Sulawesi island, Kalimantan island, Papua island

don´t have individual electricity interconnection system across the island. In addition,

smaller islands have their own transmission electricity and disconnected from each other

[46].

3. Electricity distribution system

The present system serves to deliver electricity from electricity transmission system to end-

user. In addition to changing the voltage, the task of distribution substation is to isolate faults

in either the transmission or distribution system. At primary distribution substation, the

voltage is stepped down from high voltage level to medium level. Then, the electrical power

is forwarded from primary distribution substation to secondary distribution system via

primary distribution line at medium voltage. The electricity reaches small industrial and

commercial customers in the form of three phase at low voltage via secondary distribution

line. In case of residential customer, the electricity reaches them in the form of single phase

via secondary distribution line at low voltage. One of main elements in electricity

transmission and distribution system is power line. Two most widely used types of

transmission and distribution line in Indonesia: (1) Overhead lines which has upsides such

as low initial and repairment cost. On the other hand, it has downsides such as prone to

storm and wind as well as has low aesthetics. (2) Underground lines which offer advantages

like not affected by storm and wind and high aesthetics. On the other hand, it has

disadvantages such as high initial and repairment cost and vulnerable to storm surge and

flooding from corrosive saltwater, rainfall or melting ice and snow [42].

3.2 Current Grid Codes of Indonesia

The regulation of Indonesia for renewable energy power plant connected to electricity

distribution system is based on IEEE technical guidance. One of them is IEEE 1547 [48].

Moreover, the summary of Indonesia´s grid code is based on regulations stated in Table 3.

2.


Organization Title Version

PLN

(TSO & DSO

in Indonesia)

Pedoman Penyambungan Pembangkit

Listrik Energi Terbarukan ke Sistem

Distribusi PLN

(Guideline for Renewable Energy Power

Plant Connected to Electricity Distribution

System of PLN)

July, 2014

PLN

(TSO & DSO

in Indonesia)

Persyaratan Umum dan Metode Uji Inverter

Untuk Pembangkit Listrik Tenaga Surya

(PLTS)

(General Requirement and Compliance Test

Methodology for PV inverter)

November, 2012

Table 3. 2 Regulation and grid code under study

The scope of above-mentioned regulation is explained in Table 3. 3.

Parameter Value

Grid Voltage (kV) Up to 20 kV

Collection Grid Topology of Network Radial

Size of Power Generation Up to 10 MW

Table 3. 3 The scope of regulation for grid code


The range of normal operating frequency and voltage along with minimum duration to remain

online are listed in Table 3. 4 and Table 3. 5, respectively.

Nominal Frequency,

fn (Hz)

Range of Normal

Operating Frequency

(Hz)

Minimum Duration

50

x<49 0.2 s


x >51 0.2 s



Range of Normal

Operating Voltage (pu)

Minimum Duration

x<0.5 0.1 s

0.5≤x<0.85 2 s

0.85-1.10 Continuous

1.1<x≤1.35 2 s

x≥1.35 0.1 s

Table 3. 5 Range of normal operating voltage


Table 3. 6 outlines the active power and frequency support requirements. It can be deduced

that active power and frequency support requirement is not stated in Indonesia’s regulation.


Frequency response or control. No


power curtailment is not stated

No


reserve is not laid down

No

Power gradient. power gradient or ramp rate

or is not stated

No

Table 3. 6 Active power and frequency requirement


Table 3. 7 outlines the reactive power and voltage support requirements.



Voltage control. No

Reactive power control. No

Power factor control. power factor control is detailed

below

Yes




Solar PVPP must be capable of providing the reactive power from Q1 to Q2 with regard to the

power factor between PF1 to PF2 (i.e. zone 2). Table 3. 8 establishes the parameters



PF1 0.85

PF2 -0.9

Q1 0.62

Q2 -0.48

P1 NA



Table 3. 9 lists fault-ride-through requirement. It is deduced that fault-ride-through requirement

is not stated in Indonesia’s regulation.


Low voltage fault-ride-through capability No


due to symmetrical and asymmetrical fault

High voltage fault-ride-through capability

due to symmetrical and asymmetrical fault

No

Reactive current injection No


3.3 Grid Code Proposal

There are there approaches for proposing grid code design:

1. Geographic approach Table 3. 10 summarizes the geographic condition of Indonesia based on relevant

parameters.

Parameter Response

Type of Nation Archipelago

Number of Major Islands

Five (5) Sumatera island (land area of 480,793

km2) Java island (land area of 129,438 km2) Kalimantan island (land area of 544,150

km2) Sulawesi island (land area of 188,522

km2) Papua island (land area of 418,707

km2)

Number of Small Islands 17,504 (average land area per island of 5,000 km2)

Number of Land Borders

Three (3) With Malaysia in Kalimantan island With Timor Leste in Nusa Tenggara

island With Papua New Guinea in Papua

island

Table 3. 10 The geographic condition of Indonesia [49]

Furthermore, Table 3. 11 and Table 3. 12 summarize the geographic condition of Puerto Rico and Denmark based on relevant parameters, respectively.

Parameter Response


Number of Major Islands One (1) with land area of 8,868 km2

Number of Small Islands Three (3) with average land area per island of 30 km2

Number of Land Borders None

Table 3. 11 The geographic condition of Puerto Rico [50]


Parameter Response


Number of Major Islands One (1) with land area of 42,916 km2

Number of Small Islands Four hundred (400)

Number of Land Borders One (1) with Germany in the south

Table 3. 12 The geographic condition of Denmark [51]

In addition, Table 3. 13 and Table 3. 14 summarize the geographic condition of Germany and European Union based on relevant parameters, respectively.

Parameter Response

Type of Nation Non-archipelago

Number of Major Islands One (1) (land area of 357,104 km2)

Number of Small Islands Ten (10)

Number of Land Borders

Ten (10) countries with the Netherlands,

Belgium, Luxemburg, France, Switzerland,

Liechteinsten, Austria, Czechia, Poland and

Denmark.

Table 3. 13 The geographic condition of Germany [52]

Parameter Response

Type of Nation Non-archipelago

Number of Major Islands One (1) (land area of 4,369,364 km2)

Number of Small Islands Hundreds

Number of Land Borders Five (5) countries that are Russia, Belarus,

Ukraine, Moldova and Turkey

Table 3. 14 The geographic condition of European Union [53]

Based on description above, it is noted that Puerto Rico and Denmark have similar geographical condition with Indonesia´s geographical condition.

2. Electricity generation mix approach

Table 3. 15 summarizes the fraction of solar power in electricity generation described in

chapter 2. It is expected that Indonesia´s landscape of electricity generation by 2025 will be

similar to Puerto Rico´s electricity generation in 2017 and Denmark´s electricity generation in

2016.

Nation Percentage of Solar Power in Electricity Generation

Indonesia 1% based on Energy Policy by 2025

Puerto Rico 1% in 2017

Denmark 1% in 2016

Germany 3% in 2017


European Union 3% in 2016

Table 3. 15 Solar power percentage in electricity generation

Electricity interconnection system approach Table 3. 16 summarizes the status of Indonesia´s electricity interconnection system.

Parameter Response

Domestic interconnection One (1) interconnection that links Java

island, Madura island and Bali island

International interconnection None

Table 3. 16 Status of Indonesia´s electricity interconnection system [46] [47]

Table 3. 17 and Table 3. 18 list the status of Puerto Rico and Denmark´s electricity

interconnection system.

Parameter Response

Domestic interconnection Interconnection across the nation

International interconnection None

Table 3. 17 Status of Puerto Rico´s electricity interconnection system [54]

Parameter Response


International interconnection Three (3) interconnections that links the

nation to Norway, Sweden and Germany

Table 3. 18 Status of Denmark´s electricity interconnection system [55] [56]

And Table Table 3. 19 and Table 3. 20 summarizes the status of Germany’s and EU’s

electricity interconnection system.

Parameter Response



International interconnection

Nine (9) interconnections that link the

nation to Poland, Czechia, Austria,

Switzerland, Luxemburg, Belgium, the

Netherland, Denmark and Sweden

Table 3. 19 Status of Germany´s electricity interconnection system [56]

Parameter Response

Domestic interconnection Interconnection across the region

International interconnection

Five (5) interconnections that connects

the region to Russia, Belarussia,

Ukraine, Turkey and Morocco

Table 3. 20 Status of EU´s electricity interconnection system [56]

Considering above approaches, international grid codes under study that suits the most

current condition of Indonesia´s electricity system during the transition period to renewable

energy are grid codes of Puerto Rico and Denmark. Moreover, both sets of grid codes are

aligned with Indonesia´s energy policy to attain 1% solar power in electricity generation by

2025. Accordingly, the grid code proposal for solar PVPP in Indonesia especially in major and

small islands will be based on grid codes of Denmark and Puerto Rico. Note that Denmark

and Puerto Rico have an average closest individual area of the higher and smaller islands in

Indonesia and similar electricity generation mix to the expected one of Indonesia in 2025.


Table 3. 21 and Table 3. 22 summarize the range of normal operating frequency for major

islands and small islands, respectively.



Minimum Duration

50

x<47 Instantaneous trip


x>52 Instantaneous trip

Table 3. 21 Normal operating frequency for major islands



Minimum Duration


47.1≤x<47.9 10 sec



51.3<x≤52.1 30 sec


Table 3. 22 Normal operating frequency for minor islands

Table 3. 23 lists the normal operating voltage for major island and small islands.

Range of Normal Operating Voltage (pu)

Minimum Duration

Major Islands Small Islands

0.90-1.10 0.85-1.15 Continuous

Table 3. 23 Normal operating voltatge for small islands


Table 3. 24 summarizes the active power and frequency support for solar PVPP in major

islands and smalls islands.

Requirements for a 1 MW Solar PVPP Major islands Small islands



Yes Yes

Constraint functions. absolute production or


Yes Yes

Constraint functions. delta production or power


No Yes

Constraint functions. power gradient or ramp

rate is detailed below

Yes Yes


Frequency Response

Table 3. 25 lists the parameters for frequency response or control depicted in Figure 2. 6 for

solar PVPP in major islands, small islands with small frequency deviation (i.e. less than 0.25

Hz) and large frequency deviation (i.e. larger than 0.25 Hz).

Parameter Major Islands Small Islands Small Islands


(small frequency

deviation)

(large frequency

deviation)

fmin 47.0 Hz 47.1 Hz 47.1 Hz

f1 NA ≥49.745 Hz <49.745 Hz

f2 NA 49.995 Hz 49.995 Hz

f3 50.0-52.0 Hz

(aw-TSO)

50.2 Hz

(standard value)

50.005 Hz 50.005 Hz

f4 NA ≤50.255 Hz >50.255 Hz

fmax 52.0 Hz 52.1 52.1

Upward droop constant NA 5% as a function of

nominal output

power (Pn)

5% as a function of

nominal output

power (Pn)

Downward droop

constant

2-12%

(aw-TSO)

4% as a function of

actual output

power (Pac)

(standard value)

5% as a function of

nominal output

power (Pn)

5% as a function of

nominal output

power (Pn)


droops

2 s (only downward

droop is

applicable)

<1 s <1 s


droops

20 s (only

downward droop is

applicable)

NS NS


Actual power NA NS ≥10% of nominal

output power

Table 3. 25 Parameters in frequency response or control for major islands and small islands


Table 3. 26 describes the types of constraint functions applied to solar PVPP in major islands

and small islands.

Type of Constraint Functions Major Islands Small Islands

Absolute production aw-TSO aw-TSO

Delta production NA 10% nominal output

power ≤ x ≤ 100%


Ramp rate

• Rate of increase of power

• Rate of decrease of power

• Rate of increase of power when an absolute production constraint turns off

• Rate of decrease of power when an absolute production constraint turns on

100 kW/s 10% of nominal output

power per minute with

tolerance of 10%

Table 3. 26 Types of constraint functions

*aw-TSO: agreed with TSO


Table 3. 27 lists the reactive power and voltage support for solar PVPP in major islands and

small islands, respectively. For the major islands, the control functions are exclusive

meaning only one of three functions can be activated at a time.


Requirement for a 1 MW solar PVPP Major Islands Small Islands

Voltage control. voltage control is detailed below No Yes

Reactive power control*. reactive power control is

detailed below

Yes Yes

Power factor control*. power factor control is

detailed below

Yes Yes

Table 3. 27 Reactive power and voltage support for solar PVPP in major islands and small

islands

Nb: * for solar PVPP in major islands, reactive power control, power factor control and

automatic power factor control must not be performed in the absence of agreement with

transmission system operator

Reactive power and power factor control requirements are thought to be also needed for solar

PVPP in small islands to ensure security, stability and reliability of the electrical grid as

electrical grid in small islands are naturally less robust than that in major islands.

Voltage Control

Table 3. 28 illustrates parameters with regards to voltage control function for small islands as

depicted in Figure 2. 8.

Parameters Value

Deadband 0.999pu≤x≤1.001pu

Upward droop function 0%<x≤10%

Downward droop function 0%<x≤10%

Time response 1s for 95% total reactive power

Upper limit of reactive power

delivery

0.62 of actual active power (Pac)

Lower limit of reactive power

delivery

-0.62 of actual active power (Pac)




Table 3. 29 lists the parameters in reactive power control depicted in Figure 2. 10 for solar

PVPP in major islands and small islands.

Parameters Value

Type of zone 2

PF1 0.9

PF2 -0.9

Q1 0.48

Q2 -0.48

P1 NA

Time response

(100% of steady-

state response)

10 s


Steady-state mode turns on under the condition where voltage droop is not taking action

whereas dynamic mode turns on under the condition where voltage droop is being applied.


As illustrated in Table 3. 29, solar PVPP in both major and small islands must be capable of

operating at PF between 0.9 and -0.9. In addition, the solar PVPP must reach power factor

setpoint by 10 s (i.e. time response of 10 s).


Table 3. 30 lists the fault-ride-through requirement for solar PVPP in major islands and small

islands.

Requirement for 1 MW solar PVPP Major

Islands

Small

Islands


Low-voltage-ride-through capability due

to symmetrical and asymmetrical fault

No Yes

High-voltage-ride-through capability due

to symmetrical and asymmetrical fault

No Yes

Reactive current injection No Yes


Table 3. 31 explains the parameters in low-voltage-ride-through (LVRT) requirement described

in Fig.2.11 for solar PVPP in small islands.

Parameters Value

V1 0

V2 0.1 pu

V3 0.85 pu

t1 600 ms

t2 3 s

Table 3. 31 Parameters in LVRT requirement

Furthermore, Table 3. 32 describes the parameters with regards to high-voltage-ride-through

(HVRT) requirement depicted in Fig. 2.12 for small islands.

Parameters Value

V1 1.4 pu

V2 1.3 pu

V3 1.15 pu

t1 150 ms

t2 1 s


t3 3 s

Table 3. 32 Parameters in HVRT requirement

During undervoltage fault condition, solar PVPP in small islands must operate on reactive

current injection mode depicted in Figure 2. 13 with parameters listed in Table 3. 33.

Parameters Value

Droop constant 1%≤x≤5%

Deadband 15%

X1 aw-TSO

X2 NS

Table 3. 33 Parameters in reactive current injection requirement


NS: not stated


Introduction and Control of Solar Photovoltaics

Power Plant

Introduction

Solar photovoltaics power plant is generally split into three sizes which are small scale, large

scale and very large scale. According to International Energy Agency, the power rating of small

scale photovoltaics power plant (PVPP) ranges from 25 kW to 1 MW, large scale photovoltaics

power plant (LS-PVPP) from 1 MW to 100 MW and very large scale photovoltaics power plant

(VLS-PVPP) from 100 MW to GW [57]. Electrical components are the basis of solar PVPP.

They are basically assigned to [58]: (1) to transform solar energy into electricity. (2) to connect

the PVPP to electrical grid in grid-connected PVPP application. (3) to ensure appropriate

performance.

The basic electrical components basically deployed in solar PVPP are: PV panels, PV inverters

and transformers. PV panel is a block where the sunlight arrives on. A PV string is a set of PV

panels that are electrically connected in series whereas a PV array is a set of PV strings that

are electrically connected in parallel. The objective of PV string and PV array structure is to

generate desired current and voltage that a single PV panel might not.

PV inverter is an electrical component whose function is to transform the dc current to ac

current. Basically, there are four (4) basic inverter topologies in solar PVPP as shown in Figure

4. 1. Inverter topology number one is called central inverter in which the whole set of PV arrays

is linked to a single PV inverter. Inverter topology number two is called string inverter where

each PV string is connected to a single PV inverter. Inverter topology number three is called

multistring topology in which each PV string is linked to a single dc-dc converter then several

dc-dc converters are connected to a single PV inverter (dc-ac inverter). And the last inverter

topology is called module integrated inverter in which each PV panel is connected to a single

PV inverter. As for central topology inverter, since a lot of PV strings are connected in parallel

it will create high dc voltage variation. However, due to its robustness and low number of

inverters needed in central inverter topology, it makes central inverter topology most widely

used in solar PVPP. Therefore, most solar PVPPs are based on central inverter topology [58].


1) central inverter 2. string inverter 3. multistring inverter 4. module integrated

Figure 4. 1 PV inverter topologies [adapted from [58]].

Solar PVPP is also classified based on the internal collection grid and how the PV generator

is connected to electrical grid. A PV generator is referred to a set of PV arrays and PV

inverters along with the transformers. In radial collection topology, several PV generators

connected to one feeder as shown in Figure 4. 2. This topology is most used in LS-PVPPs

since it is the cheapest and simplest. However, its disadvantage is low reliability. In case a

PV inverter fails, the total power production will not be affected significantly [58].

In order to improve the reliability of LS-PVPPs in general, ring collection topology is used.

The connection is built on radial collection topology but it adds another feeder that connects

the other side of PV generators (Figure 4. 3). In case one of the PV generators is lost, then

the PV generators connected to the other side of the feeder can still give power to the LS-

PVPP. The downside is the cost and complexity of the installation.

In star collection topology, each PV generator is connected to the main collector. Normally, the

collector is placed in the middle of the LS-PVPP to have the same proximities with all PV

generators that result in the same losses between them (Figure 4. 4). The star collection

topology has the highest reliability among the grid collection topologies. Its downside is one

feeder for each generator results in high total cost.


Figure 4. 2 Radial collection grid topology [58]

Figure 4. 3 Ring collection grid topology [58]


Figure 4. 4 Star collection grid topology [58]

To understand more about function of each electrical component and modelling approach in

solar PVPP, following sections are devoted to describe basic electrical components one by

one in solar PVPP.

PV Panels

PV panel is composed of solar cells. The function of solar cells is to transform solar energy

into electricity [59]. A set of solar cells are connected in series and then enclosed in a special

frame to build the PV panel [60].

There are various materials of solar cells that have different overall efficiencies of the PV

panels. The elementary type, crystalline (c – Si) and multicrystalline (m – Si) silicon, offers

efficiency of approximately 20 % [61]. Other type, thin film solar cells constituting

amorphous silicon (a-Si) offer efficiency approximately from 6.9% to 9% [61] [62]. Thin film

solar cells constituting other material like copper indium diselenide (CuInSe2 – CIS) and

Cadmium telluride (Cd-Te) presents efficiency approximately 15% [59] and 12% [61]

respectively.

The power generation by solar PVPP starts with the incidence of light on the solar cell. It results

in charge carriers that originates an electric current if the cell is short-circuited [63] Adequate

energy of the incident photon produces the charges that lead to the detachment of the covalent

electrons of the semiconductor - this phenomenon depends on the semiconductor material


and on the wavelength of the incident light.

The general model of solar cell circuit is illustrated in Figure 4. 5. This circuit is made up of the

photovoltaic current (Ipv), a diode, a series resistance (Rs) and a parallel resistance (Rp).

Figure 4. 5 General model of solar cell circuit [adapted from [[64]]

The generated current (I) can be obtained by

𝐼 = 𝐼𝑝𝑣 − 𝐼𝑜 [𝑒𝑥𝑝 (𝑉+𝑅𝑠𝐼

𝑉𝑡𝑎) − 1] −

𝑉+𝑅𝑠𝐼

𝑅𝑝 (4.1)

Where Ipv and I0 represents the photovoltaic (PV) and saturation currents, respectively of the

array and V is the working voltage, Vt = NsskT/q is the thermal voltage of the array and Nss is 1

in case of solar cell and Nss is number of series-connected cells in case of solar panel, T is the

working voltage, q (= 1.6 ×10−19C) represents the electron charge, k (= 1.38 ×10−23J/K) is a

Boltzmann’s constant, α is ideality diode factor.

The solar radiation and temperature affects linearly the light-generated current of the PV cell

as expressed by Eq.4.2. [65]-[68]

𝐼𝑝𝑣 = (𝐼𝑝𝑣,𝑛 + 𝐾𝐼∆𝑇)𝐺

𝐺𝑛 (4.2)

Notice that Ipv,n (in amperes) is the light-generated current under normal condition (normally

25◦C and 1000 W/m2), KI is short circuit temperature coefficient, ΔT =T − Tn (T and Tn being

the working and nominal temperatures [i.e. 25◦C], respectively), G (watts per square meters)

is the irradiance on the device surface, and Gn is the nominal irradiance [i.e. 1000 W/m2] [69].

The saturation currents with the influence of temperature is expressed as follows

𝐼𝑜 =𝐼𝑠𝑐,𝑛+𝐾𝐼Δ𝑇

𝑒𝑥𝑝((𝑉𝑜𝑐,𝑛+𝐾𝑣Δ𝑇)/𝛼𝑉𝑡)−1 (4.3)

Where KI and Kv represent short circuit current-temperature and open circuit voltage-


temperature coefficient.

The PV cell efficiency is affected significantly by variation in series resistance (RS) but not by

variation in parallel resistance (Rp). The PV cells are generally connected in series

configuration to build a PV module with purpose of attaining desired working voltage in most

commercial PV products. Then PV modules are configured in parallel structure to form PV

string. Finally, the combination of PV strings and series-connected PV modules is called PV

array that results in the generation of desired output power. A general equivalent circuit for all

PV cells, module and array is illustrated in Figure 4. 6 [64].

Figure 4. 6 General equivalent circuits of PV [64]

Note that for a PV cell, Nss = Ns = Np = 1 and for a PV module Nss is number of cells per

module, Ns = Np = 1 and. For a PV array, Nss is number of cells per module, Ns represents

the number of series-connected PV module and Np represents the number of parallel

connections (i.e. PV string) of PV module. The mathematical formula of general model can be

expressed as follows.

𝐼 = 𝑁𝑝𝐼𝑝𝑣 − 𝑁𝑝𝐼𝑜[𝑒𝑥𝑝(𝑞(𝑉 𝑁𝑆⁄ + 𝐼𝑅𝑆 𝑁𝑝⁄ )/𝑁𝑠𝑠𝑘𝑇𝑎) − 1] (4.4)

PV Inverters

PV inverters are electronic devices that enable the conversion from dc to ac power and are

employed in different solar PVPP applications. Essentially a PV array produces dc power, then

the PV array is connected to a PV inverter to produce ac power [60]. PV inverter also has the

other function of connecting the PV array to internal ac grid.


In this master thesis, the PV inverter is modelled according to [70]. The function of central PV

inverter is to interconnect PV arrays with the 3-phase ac grid and commonly modelled as

voltage source inverter (VSI) type. At first, a PV array produces dc current and is connected to

PV inverter whose function is to convert dc current into 50 or 60 Hz ac current using local

control. The electrical scheme is illustrated in Figure 4. 7.

Figure 4. 7 Electrical scheme of on-grid solar PVPP under study [adapted from [70]]

In this scheme, the dc side is modelled as a capacitor that acts as a voltage source and the ac

side is modelled as a filter which is made up of three phase inductance which acts as a current

source.

Due to limited resources, in this master thesis an average equivalent model as in [45] is used.

The average model is based on the concept of ideal switching modulation and particularly

technique of space vector pulse width modulation (SVPWM). Consequently, the converter

model is decoupled and has 2 (two) sides. The dc side is modelled as a capacitor which acts

as current source and the ac side is modelled as an ac voltage source. The equation that

connects dc side with ac side will be described in later part. The average model is described

in Figure 4. 8.


Figure 4. 8 Electrical scheme of average on-grid solar PVPP model under study [adapted

from [45]]

In order to analyze the model of PV inverter, the PV array is represented as a current source

and the low voltage side of the transformer is represented by three voltage sources, vza, vzb

and vzc respectively as sketched in Figure 4. 9.

Figure 4. 9 Electrical scheme of average PV inverter model under study [adapted from [45]]

4.3.1 Local Control of PV Inverter

Park transformation plays an important role in the general control scheme in a way simplifying

the control algorithm. The general control of PV inverter is sketched in Figure 4. 10.

First of all, vzq component is obtained by means of phase locked loop (PLL) with PI controller

calculating the angle θ that results in vzd = 0. Considering vzd = 0, the active (Pz) and reactive

power (Qz) delivered to the grid can be calculated based on equation 4.5 and 4.6 as follows.

P𝑧 =3

2(𝑣𝑧𝑞𝑖𝑞) (4.5)

Q𝑧 =3

2(𝑣𝑧𝑞𝑖𝑑) (4.6)


Figure 4. 10 General control scheme of PV inverter

Active (Pz) and reactive power (Qz) can be controlled separately by means of control of iq and

id components, respectively. Based on the dc voltage measurement (Vdc) and the dc voltage

setpoint (𝑉𝑑𝑐∗ ), the reference computation block calculates the desired current in the q axis (𝑖𝑞

∗)

and d axis (𝑖𝑑∗ ) using PI controller as given in equation 4.7 and 4.8, respectively.

𝑖𝑞∗ =

2

3

𝑃𝑧∗

𝑣𝑧𝑞 (4.7)

𝑖𝑑∗ =

2

3

𝑄𝑧∗

𝑣𝑧𝑞 (4.8)

𝑃𝑧∗ and 𝑄𝑧

∗ are the setpoints of active and reactive power delivered to the grid, respectively.

The main function of MPPT is to generate the dc voltage setpoint (𝑉𝑑𝑐∗ ) and 𝑉𝑑𝑐

∗ is related to

the active power. It is not always the case the PV array has to work at the maximum power

point (MPP) since in some cases PV array is expected to generate necessary voltage that

leads to the desired active power.

The main function of current loop block is to compute the voltage (𝑣𝑙𝑞∗ , 𝑣𝑙𝑑

∗ ) in qd0 frame to be

applied by the PV inverter by taking into account the desired current (𝑖𝑞∗ , 𝑖𝑑

∗ ) and current

measurement (iq,id) in qd0 frame. Then the SVPWM technique is used to modulate these

voltages. In fact, these voltages are applied directly to three voltage sources by using the anti-


Park transformation (i.e. the technique of anti-park transformation is embedded in voltage

modulation block) since average model is used in this master thesis.

MPPT

Two functions that MPPT may have are (1) in case there is no PPC in the solar PV facility, it

is to calculate the dc voltage setpoint (𝑣𝑑𝑐∗ ) to produce maximum power based on PV array

behavior and environmental conditions (i.e. MPP mode). (2) in case there is PPC in the solar

PV facility, MPPT can perform power curtailment by computing the dc voltage setpoint (𝑣𝑑𝑐∗ )

to generate a desired active power (i.e. active power setpoint mode). MPPT algorithms are

essentially based on heuristic technique. The most widespread algorithm is so-called perturb

and observed (P&O).

Regarding the first function, this method measures the generated active power (Pz) of PV array

and changes the voltage supplied (vdc) by PV array to the PV inverter. Then, the system will

measure the generated active power again (Pz(k)) and compare it to the previous generated

active power (Pz(k-1)). In case the increment of vdc results in the increment of Pz(k) then the

system will increase vdc again until MPP is reached (vdc = 𝑣𝑑𝑐∗ ). However, in case the increment

of vdc results in the decrement of Pz(k) then the system will lower the vdc in the next step. On the

other hand, in case the decrement of vdc results in the increment of Pz(k) then the system will

decrease vdc again until MPP is reached. Then, in case the decrement of vdc results in the

decrement of Pz(k) then the system will raise the vdc in the next step.

With regards to the second function, when the PV array is expected to deliver certain amount

of active power (Pz) according to active power setpoint (Pz*) (i.e. not maximum power), the PV

array must operate outside of its MPP. It is required to operate the PV array in the right zone

of maximum power point to prevent Vdc is lower than Vdcmin. In case the active power setpoint

(𝑃𝑧∗) is lower than Pz then voltage increment must be applied. When the Pz is equal to the 𝑃𝑧

∗

the aforementioned MPPT algorithm is implemented which leads to the condition of 𝑃𝑧∗ > 𝑃𝑧

and supplied voltage (vdc) increases. The other observation is in case Pz cannot reach 𝑃𝑧∗, the

algorithm will be continuously performing the MPPT. In the end, 𝑃𝑧∗ is greater than maximum

active power (Pz) of the PV array. The corresponding flowchart for active power setpoint mode

(i.e. not MPP mode) is illustrated in Fig. 4.11.


Fig.4.11 MPPT algorithm for active power setpoint mode

Master Control by Power Plant Controller

The PV inverters are capable of performing their own local controls in compliance with the

active power and reactive power setpoints established by PPC. These setpoints contain

desired value of each active and reactive power to be met at the PCC. Hence, PPC is the

responsible device to drive the active power and frequency action as well as reactive power

and voltage regulation action described below. In contrast, FRT requirement is satisfied by the

local controls built in the PV inverters.

Grid code requirements from operational perspective that are satisfied by PPC are.

1) Active power and frequency regulation action.

The frequency support is used to sustain the grid frequency in determinate ranges

around its nominal value by regulating active power output of solar PVPP. The active

power and frequency regulation action can be in the following form.


• Active power curtailment: the responsible system operator sends the active power

setpoint that must be satisfied at PCC.

• Frequency regulation by droop curve: the responsible system operator establishes

a curve which preset an increase or decrease of the active power output delivered

at PCC as a function of the measured frequency.

• Ramp rate restriction: the active power variation may be limited by a ramp rate

when transitions (such as absolute production and power reserve) occur. This may

also apply to reactive power output.

2) Reactive power and voltage regulation action

The solar PVPP is required to help sustaining the grid voltage level. Hence, a minimum

reactive power capability is established and ancillary devices (e.g. FACTS or capacitor

banks) can help to meet the capability limit. The reactive power and voltage regulation

action may be in the following form.

• Reactive power setpoint: the responsible system operator sends reactive power

setpoint that must be satisfied by solar PVPP at the PCC.

• Voltage regulation by droop curve: the responsible system operator establishes a

droop curve that consists of preset the reactive power depending on the voltage

level at the PCC.

• Power factor setpoint: the responsible system operator sends power factor that

must be met by solar PVPP at the PCC.

The active power control scheme in this master thesis is adopted from [28] and limited to active

power curtailment using MPPT function in the PV inverter. As depicted in Figure 4. 11, the

control scheme is split into reference computation block, the controller and the dispatch

system. The reference computation block calculates the active power setpoints (P*) that must

be satisfied at PCC.

Once P* is calculated, the controller computes the aggregated power (Ptot) that must be

delivered by all PV inverters. This controller is based on a typical PI controller that ensures no

error (i.e. error = 0) between P* and the measured power (P) at PCC in normal operating

condition.


Figure 4. 11 Typical LS-PVPP layout including power plant control scheme [28]

The reactive power control is carried out in a similar way with active power control as illustrated

in Figure 4. 11. In this master thesis, ancillary devices (i.e. FACTS device and capacitor banks)

are not employed in the model.

In contrast to the active power and frequency regulation action, the reactive power and voltage

regulation action does not require simultaneous operations such as reactive power setpoint

and voltage control. Thus, a mode selector is employed to choose the way to compute desired

reactive power setpoint (𝑄∗) from three options that are reactive power control, voltage control

and power factor control.

In case reactive power control is chosen, the responsible system operator sends a reactive

power setpoint (QTSO) and 𝑄∗ = 𝑄𝑇𝑆𝑂. In case power factor control is chosen, the

corresponding desired reactive power is expressed in Eq. 4.9.

𝑄𝑇𝑆𝑂 = 𝑃 ∙sin(𝜑)𝑇𝑆𝑂

cos(𝜑)𝑇𝑆𝑂 (4.9)

Where P represents the measured active power at PCC and cos(𝜑)𝑇𝑆𝑂 represents the power

factor setpoint.

In case the voltage control is chosen, 𝑄𝑇𝑆𝑂 is computed according to voltage droop curve


illustrated in Figure 4. 12. In this context, due to the entire plant operation, it is needed to filter

the voltage measurement (V) to obtain droop input (V´).

Figure 4. 12 Voltage control function [28]

Next, the controller computes the reactive power (Qtot) that PV inverters have to deliver by

means of PI controller as depicted in Figure 4. 12. The corresponding p.u. value of β signal is

obtained by dividing Qtot by Qplant. Where Qplant represents the nominal reactive power of the

solar PVPP. Each PV inverter i receives β signal and computes its local reactive power setpoint

as follows.

𝑄𝑖𝑛𝑣,𝑖∗ = 𝛽 ∙ 𝑄𝑛𝑜𝑚,𝑖 (4.10)

Notice 𝑄𝑖𝑛𝑣,𝑖∗ and 𝑄𝑛𝑜𝑚,𝑖 represents the local reactive power setpoint and the nominal reactive

power of the inverter i, respectively.


Modelling and Simulation of Solar PVPP

The modelling approach for each electrical element is described one by one below.

PV Arrays

The PV module constituting the PV arrays in this model is KC200 GT solar module from

Kyocera company. This module possesses characteristics listed in Table 5. 1 under standard

test condition (STC) in which the working temperature (T) is 25oC and solar irradiance (G) is

1000 W/m2 [71].

No. Electrical characteristics

1. Maximum power (Pm) 200 W

2. Current at maximum power point (𝐼𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) 7.61 A

3. Voltage at maximum power point (𝑉𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) 26.3 V

4. Short circuit current (Isc,n) 8.21 A

5. Open circuit voltage (Voc,n) 32.9 V

Thermal characteristics

6. Short circuit current – temperature coefficient (KI) 3.18x10-3 V/oC

7. Open circuit voltage – temperature coefficient (Kv) -1.23x10-1 A/oC

Physical characteristics

8. Dimensions 1425 mm x 990 mm x 36 mm

9. Weight 18.5 kg

10. PV cell type Multicristalline silicon

11. Number of cells per module 54 cells in series

Table 5. 1 Characteristics of PV module [71]

In the solar PVPP system under study, there are two (2) PV arrays and each of them consists


of ninety two (92) PV strings (Np = 92) and each PV string is made up of twenty seven (27) PV

modules (Nm = 27) resulting in 4,968 pieces of PV module. The nominal power of each PV

array is expressed by equation 5.1.

𝑃𝑎𝑟𝑟𝑎𝑦 = 𝑁𝑝 ∙ 𝑁𝑚 ∙ 𝑃𝑚 (5.1)

Parray represents the nominal power of each PV array and it is 496.8 kW. Hence, two PV arrays

result in total nominal power of 993.6 kW.

The nominal short circuit current and the open circuit voltage of each PV array are given in

equation 5.2 and 5.3, respectively. They result in 755.32 A and 888.3 V, respectively.

𝐼𝑠𝑐𝑎𝑟𝑟𝑎𝑦= 𝑁𝑝 ∙ 𝐼𝑠𝑐,𝑛 (5.2)

𝑉𝑜𝑐𝑎𝑟𝑟𝑎𝑦= 𝑁𝑚 ∙ 𝑉𝑜𝑐,𝑛 (5.3)

The current and voltage at maximum power point of each PV array can be calculated by

equation 5.4 and 5.5. They give 700.2 A and 710.1 V, respectively.

𝐼𝑀𝑃𝑃𝑎𝑟𝑟𝑎𝑦= 𝑁𝑝 ∙ 𝐼𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒

(5.4)

𝑉𝑀𝑃𝑃𝑎𝑟𝑟𝑎𝑦= 𝑁𝑚 ∙ (𝑉𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒

) (5.5)

Figure 5. 1 and Figure 5. 2 illustrates characteristic curve of the PV module and PV array,

respectively under STC. The discrepancies in most important characteristics between

simulation model and information given by the PV module manufacturer for a PV module and

two (2) PV arrays are summarized in Table 5. 2 and Table 5. 3. As seen in Table 5. 2 and

Table 5. 3, the simulation results are similar to the information given by PV module

manufacturer.

Figure 5. 3 and Figure 5. 4 describe the PV array characteristics under variations of working

temperature (T) and irradiance (G), respectively. It is seen that the working temperature (T)

affects the open circuit voltage (Voc,n) and open circuit voltage at MPP (𝑉𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) in an

inverse way as well as short circuit current (Isc,n) and current at MPP (𝐼𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) slightly in a

linear way. On the contrary, irradiance (G) influences short circuit current (Isc,n) and current at

MPP (𝐼𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) significantly in a linear way and the open circuit voltage (Voc,n) and open

circuit voltage at MPP (𝑉𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) slighlty in a linear way.

As observed in Figure 5. 3 and Figure 5. 4 that maximum PV power changes with variation of

working temperature (T) and irradiance (G). This is summarized in Figure 5. 5 and Figure 5. 6

Therefore, it is needed to deploy maximum power point tracking (MPPT) function to search for


the maximum PV power under particular working temperature (T) and irradiance (G)

Figure 5. 1 V-I and V-P characteristic curves of PV module at T = 25oC and G = 1000 W/m2

Figure 5. 2 V-I and V-P characteristic curves of two (2) PV arrays

at T = 25oC and G = 1000 W/m2


No. PV module Simulation

Result

Error (%)

1. Maximum power (Pm) 200.16 W 0.08

2. Current at maximum power point (𝐼𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) 7.58 A -0.39

3. Voltage at maximum power point (𝑉𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) 26.38 V 0.30

4. Short circuit current (Isc,n) 8.26 A 0.61

5. Open circuit voltage (Voc,n) 32.87 V -0.09

Table 5. 2 Simulation results of PV module

No. Two (2) PV arrays Simulation

Results

Error (%)

1. Maximum power (Pm) 994,389.83 W 0.08

2. Current at maximum power point (𝐼𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) 1395.79 A -0.32

3. Voltage at maximum power point (𝑉𝑀𝑃𝑃𝑚𝑜𝑑𝑢𝑙𝑒) 712.42 V 0.33

4. Short circuit current (Isc,n) 1509.75 A -0.06

5. Open circuit voltage (Voc,n) 887.75 V -0.06

Table 5. 3 Simulation results of two (2) PV arrays


Figure 5. 3 PV arrays characteristics in function of working temperature (T)

Figure 5. 4 PV arrays characteristics in function of irradiance (G)


Figure 5. 5 Max PV power in function of temperature (T) and

at constant irradiance (G) of 1000 W/m2

Figure 5. 6 Max PV power in function of irradiance (G) and

at constant working temperature (T) of 25oC

In addition, three parameters to take into account for sizing the correct inverter linked to each

PV array is (1) 𝑉𝑚𝑖𝑛𝑀𝑃𝑃𝑇≤ 712.42 V ≤ 𝑉𝑚𝑎𝑥𝑀𝑃𝑃𝑇

, (2) 𝐼𝑖𝑛𝑝𝑢𝑡𝑚𝑎𝑥≥ 697.9 𝐴 and (3) 𝑃𝑛𝑜𝑚 ≥

497,190 𝑊 [72].


PV Inverters

The solar PVPP is modelled as in Figure 4. 8 and the PV inverter model is a ready-to-use

model that can be coupled directly with the PV arrays and the integration of transformer and

electrical grid. Each PV array is linked to a single central PV inverter resulting in the total

number of PV inverters is two (2).

In the PV inverter model, instead of one (1) PV array of approximately 1 MW linked to a single

central PV inverter, two (2) PV arrays of each maximum PV power of 500 kW connected to

two (2) central PV inverters separately are deployed. Some underlying motives for that are (1)

easy maintenance. Solar PVPP requires less maintenance than the other power plants since

it has a few moving parts. However, solar PVPP still requires little maintenance that must be

performed for determinate intervals. In case of maintenance, one (1) PV array can be isolated

at a time. As a result, the other PV array may still be online that results in the generated

maximum PV power of approximately 500 kW. (2) Higher reliability. In the event of fault that

happens to one PV array, it results in the isolation of the corresponding PV array, the other PV

array may still be in operation and produces maximum PV power of approximately 500 kW

[73]. The PV inverter model is depicted in Figure 5. 7.

In the PV inverter simulation, the grid along with the transformer are represented by three

phase ideal voltage source 400 kV (phase to phase) at 50 Hz. The maximum active power of

the PV inverter is not limited due to an approximation model is used in this master thesis. Table

5. 4 summarizes the characteristics of the PV inverter model in this master thesis. The

simulation model is run under STC.


Figure 5. 7 The layout of PV inverter model

No. Characteristics Value

Phase Lock Loop

1. Admitted peak voltage (EmPLL) 16.33x103 V

2. Kp gain (Kppll) 0.0272

3. Ki gain (KIpll) 6.0439

4. Time constant (τPLL) 4.5 ms

Current loop


5. Kp gain (Kpi) 0.0395

6. Ki gain (KIi) 0.5333

7. Time constant (τi) 1 ms

Reference computation

8. Kp gain (Kpdc) 31.1002

9. Ki gain (KIdc) 1.3817 x 104

10. Time constant (τdc) 10 ms

11. Initial dc voltage reference (Vdcref) 800 V

Table 5. 4 Characteristics of PV inverter model


5.2.1 Aggregated PV Inverter Model

Due to high computer system requirements to perform simulation of two PV arrays linked to

each individual PV inverter, in this master thesis, an aggregated PV inverter model is used.

The aggregated PV inverter model is characterized by a single PV inverter connected to one

PV array of approximately 1 MW.

As explained earlier in section 4.3.1 Local Control of PV inverter particularly about MPPT that

based on dc voltage measurement (Vdc) and dc voltage setpoint (𝑉𝑑𝑐∗ ), MPPT controller

computes desired current in the q axis (𝑖𝑞∗) and d axis (𝑖𝑑

∗ ). Since dc voltage measurement

(Vdc) is dependent on the power profile of PV array (i.e. work temperature (T) and irradiance

(G)), in the simplified PV inverter model the current setpoint in the q axis (𝑖𝑞∗) can be calculated

by.

𝑖𝑞∗ =

2

3

𝑃𝑧∗

𝑣𝑧𝑞 if 𝑃𝑧

∗ ≤ 𝑃𝑎𝑣 (5.6)

Or

𝑖𝑞∗ =

2

3

𝑃𝑎𝑣

𝑣𝑧𝑞 if 𝑃𝑧

∗ ≥ 𝑃𝑎𝑣 (5.7)

Where 𝑃𝑧∗ is active power setpoint and Pav is available power.

PV Plant Model

The PV plant model is a ready-to-use model for the purpose of master control simulation. It

consists of one aggregrated PV array linked to a single central PV inverter. The PV inverter is

connected directly to electrical grid. The internal impedance of electrical grid includes the

inductor-equivalent model of LV/MV transformer. Figure 5. 8 and Table 5. 5 depicts the PV

plant model and lists the parameter in PV plant model, respectively.


Figure 5. 8 The layout of PV plant simulation model

Voltage (kV) Short circuit power (MVA) Reactance to resistance

(X/R)

20 500 1/3

Table 5. 5 Equivalent grid data


Results and Discussion

Maximum Power Point Tracking (MPPT)

6.2.1 Maximum Power Point (MPP) Mode

In this section, the maximum power point tracking (MPPT) function of PV inverters developed

by the student is tested for each particular working temperature (T) and irradiance (G). The

simulation result of MPTT function for variation of working temperature (T) and at constant

irradiance (G) of 1000 W/m2 as well as variation of irradiance (G) and at constant working

temperature of (T) of 25oC is depicted in Figure 6. 1 and Figure 6. 2, respectively.

As seen in Figure 6. 1, due to inizialitation period that is unrelated to the observation of MPP,

the simulation result is shown from second 1. Table 6. 1 compares the maximum PV power in

function of working temperature (T) and at constant irradiance (G) of 1000 W/m2 based on PV

array characteristics depicted in Figure 5. 5 with maximum PV power based on MPPT function

in PV inverter depicted in Figure 6. 1. Additonally, Table 6. 2 compares the maximum PV power

in function of irradiance (G) and at constant working temperature (T) of 25oC based on PV

array characteristics illustrated in Figure 5. 6 with maximum PV power based on MPPT

function in PV inverter illustrated in Figure 6. 2.

As observed in Table 6. 1 and Table 6. 2, the MPPT function developed by the student fits the

PV array characteristics well. The MPPT function creates little discrepancy because of the

pertubation in MPPT algorithm during maximum power point (MPP) searching.


Figure 6. 1 PV power in function of working temperature (T) and

at constant irradiance (G) of 1000 W/m2

Figure 6. 2 PV power in function of irradiance (G) and

at working temperature (T) of 25oC

No. Period (s)

Working

Temperature

(oC)

Maximum PV Power Based on

PV Array Characteristics (Watt)

Maximum PV Power Based

on MPPT function (Watt)

Discrepancy

(%)

1. 1≤t<4 0 1,115,386 1,117,000 0.14


2. 4≤t<9 25 994,390 996,000 0.16

3. 9≤t<14 50 873,537 875,300 0.20

4. 14≤t<20 75 753,388 755,100 0.23

Table 6. 1 Maximum PV power in function of working temperature (T) and at constant

irradiance (G) of 1000 W/m2

No. Period (s) Irradiance

(W/m2)

Maximum PV Power Based

on PV Array Characteristics

(Watt)

Maximum PV Power

Based on MPPT function

(Watt)

Discrepancy

(%)

1. 1≤t<5 200 180,325 185,200 2.63

2. 5≤t<9 400 382,422 386,900 1.16

3. 9≤t<13 600 587,034 590,800 0.64

4. 13≤t<17 800 791,442 794,200 0.35

5. 17≤t<20 1000 994,390 996,100 0.17

Table 6. 2 Maximum PV power in function of irradiance (G) and at constant working

temperature (T) of 1000 W/m2

6.2.1 Active Power Setpoint Mode (i.e. Power Curtailment)

As mentioned in section 4.3.1 Local Control PV Inverter particularly about MPPT function,

MPPT function can carry out power curtailment by calculating the dc voltage setpoint (𝑣𝑑𝑐∗ ) to

generate a desired active power (𝑃𝑧∗). In this mode there are two (2) options which are (1) In

case active power setpoint (𝑃𝑧∗) is greater than available power (Pav) (i.e. maximum power

based on PV array characteristics), then the MPPT function computes the dc voltage setpoint

(𝑣𝑑𝑐∗ ) that corresponds to the available power (Pav). (2) In case active power setpoint (𝑃𝑧

∗) is

lower than available power (Pav), then MPPT function computes the dc voltage setpoint (𝑣𝑑𝑐∗ )

that corresponds to the active power setpoint (𝑃𝑧∗).

Option 1 is depicted in

Figure 6. 3, the active power setpoint mode is activated at second 0.5. Hence, the simulation

result is displayed from second 0.5. When the active power setpoint (𝑃𝑧∗) is set to 1.5 MW,

then the MPPT function computes the dc voltage setpoint (𝑣𝑑𝑐∗ ) of approximately 713 V that

leads to the available power (Pav) of around 1 MW under STC as verified earlier. It is observed


that at second 0.5 the measured voltage (vdc) starts to decrease gradually from initial dc voltage

reference (Vdcref) of 800 V to dc voltage setpoint (𝑣𝑑𝑐∗ ) of approximately 713 V. At second 3.4,

measured voltage (vdc) reaches dc voltage setpoint (𝑣𝑑𝑐∗ ) of approximately 713 V that makes

generated active power equal to available power (Pav) of around 1 MW.

Option 2 is illustrated in Figure 6. 4, in a similar manner, the active power setpoint mode is

engaged in second 0.5. Hence, the simulation result is displayed from second 0.5. The active

power setpoint (𝑃𝑧∗) is depicted in brown line whereas the generated active power is

represented by blue line. When the active power setpoint (𝑃𝑧∗) is set to 0.5 MW, then the MPPT

function computes the dc voltage setpoint (𝑣𝑑𝑐∗ ) of 845 V that corresponds the active power

setpoint (𝑃𝑧∗) of approximately 0.5 MW. It is seen that measured voltage (vdc) starts rising from

initial dc voltage reference (Vdcref) of 800 V to dc voltage setpoint (𝑣𝑑𝑐∗ ) of approximately 845

V. At second 2, the measured voltage (vdc) reaches dc voltage setpoint (𝑣𝑑𝑐∗ ) that makes the

generated power equal to the active power setpoint (𝑃𝑧∗) of around 0.5 MW.

Figure 6. 3 Option 1 in active power setpoint mode


Figure 6. 4 Option 2 in active power setpoint mode

Voltage Control and Reactive Power Regulation Action

As described in section 4.4 Master Control by Power Plant Controller, voltage control and

reactive power regulation action can be in the form of (1) reactive power control, (2) voltage

control by droop curve and (3) power factor control. In this section, the reactive power and

voltage control regulation set out in grid code proposal for solar PVPP in major islands and

small islands in Indonesia described in section 3.3.3 Reactive Power and Voltage Support is

simulated. Furthermore, the response to this regulation is observed and explained.

6.2.1 Voltage Control

As explained earlier in section 3.3.3 Reactive Power and Voltage Support especially in Table

3.28, the grid code proposal sets out voltage control regulation for solar PVPP in small islands.

The proposed voltage control is adopted from Puerto Rico´s grid code.


Figure 6. 5 depicts the response to voltage control function. In this simulation, the MPPT

particularly maximum power point mode and the voltage control are engaged concurrently.

The simulation result is displayed from second 0.2 since the mode of maximum active power

in MPPT and voltage control turn on at second 0.2. Hence, initialization takes place that is

unrelated to the simulation analysis lasts until second 0.2. In order to see the response under

the strictest requirement, the maximum allowable and minimum allowable voltage droop

gradient of 10% and -10% are applied in turn. Table 6. 3 lists the parameters in response to

voltage control function.

As observed in Figure 6. 5, at second 0.2 the solar PVPP starts to produce active power from

approximately 815 kW and at second 2.5 it eventually attains the maximum power point (MPP)

of 993.6 kW. In fact, due to perturb and observe method in MPPT algorithm, the generated

active power oscillates around the maximum power point (MPP) (i.e. not remains at 993.6 kW).

Regarding the reactive power output, as stated in Table 6. 3, from second 0.2 to 3.1, by default

the solar PVPP absorbs reactive power in the range of -2.2 W to -11,020 W due to the voltage

at the PCC of between 20,030 V and 20,040 V that is supposed to be absolute 20,000 V. The

deviated voltage at the PCC is because of the existence of internal impedance that leads to

the higher voltage than nominal voltage at the PCC. From second 3.1 to 5, a voltage

perturbation is simulated that leads to the voltage at the PCC of absolutes 20,000 V that places

the operating point within the deadband in voltage droop curve depicted in Figure 2. 8. As a

result, solar PVPP delivers reactive power in the range of -10,950 W to 13 W whereas

theoretically no reactive power. From second 5 to 7, another voltage perturbation is simulated

that leads the voltage at the PCC to 19,500 V that puts the operating point in the left zone of

voltage droop curve. As a result, solar PVPP produces reactive power between 125,400 W to

236,800 W. Additionally, from second 7 to 9, another voltage perturbation is simulated that

leads to the voltage at PCC of 20,540 V that puts the operating point in the right zone of voltage

droop curve. As a result, the solar PVPP absorbs reactive power in the range of -40,080 W to

-258,300 W. The generated reactive power fluctuates since the transient condition takes place

every time a voltage perturbation is simulated and it stays oscillating due to the perturb and

oscillation method in MPPT algorithm that affects the generated reactive power.

Table 6. 4 summarizes the parameters at a determinate point for each period. It is observed

that generated reactive powers are similar to theoretical reactive powers according to the

equation for voltage droop function described in section 2.2.3 Reactive Power and Voltage

Control Functions. The proposed voltage control function gives acceptable time response

since it takes less than 1 s to reach the 95% of steady-state response (i.e. 95% of final value

of reactive power) as listed in Table 6. 4.

In the next simulation, the minimum allowable voltage at the PCC and maximum voltage droop

function of 0.85 pu and 10% as well as the maximum allowable voltage at the PCC and


minimum allowable voltage droop function of 1.15 pu and -10%, respectively, are applied

separately.

As seen in Figure 6. 6, at the second 0.2, the solar PVPP starts producing active power of

814,900 kW and at second 2.5, the solar PVPP achieves the maximum power point (MPP) of

993,600 kW. In fact, due to perturb and observe method in MPPT algorithm, the generated

active power keeps oscillating around the maximum power point (MPP) (i.e. not remains at

993.6 kW).

Concerning reactive power output, as listed in Table 6. 5, the response to voltage control

function for periods of second 0.2 to 3.1 and second 3.1 to 5 remains the same as stated in

Table 6.3. Additionally, from second 5 to 7, another voltage perturbation is simulated that leads

the voltage at the PCC to 0.85 pu (i.e. 17,000 V) that puts the operating point in the left zone

of voltage droop curve. As a result, solar PVPP delivers reactive power between 370,800 W

and 618,400 W. Since stated in the grid code proposal that the upper limit of reactive power

output of solar PVPP is 0.62 of actual power (Pac). Hence, the maximum reactive power that

solar PVPP can produce is 618,400 W despite the voltage drop at the PCC is over 0.062 pu

(in fact, the actual voltage drop is 0.15 pu that corresponds to the reactive power production

of 1.49 MW). Then from second 7 to 9, another voltage perturbation is simulated that leads to

the voltage at PCC of 1.15 pu (i.e. 23,000 V) that puts the operating point in the right zone of

voltage droop curve. As a result, the solar PVPP absorbs reactive power in the range of -

241,600 W to -619,300 W. As stated in the grid code proposal that lower limit of reactive power

output of solar PVPP is -0.62 of actual power (Pac). Thus, the maximum reactive power output

that solar PVPP can absorb is -619,300 W despite the voltage spike at the PCC is greater than

0.062 pu (in fact, the actual voltage spike is 0.15 pu that corresponds to the reactive power

absorption of 1.49 MW). The generated reactive power keeps fluctuating since the transient

condition occurs every time a voltage perturbation is simulated and it keeps oscillating due to

the perturb and oscillation method in MPPT algorithm that affects the generated reactive

power.

Table 6. 6 lists parameters at a determinate point for each period. It is seen that generated

reactive powers are similar to theoretical reactive powers according to the equation for voltage

droop function described in section 2.2.3 Reactive Power and Voltage Control Functions. The

proposed voltage control function gives acceptable time response since it takes less than 1 s

to reach the 95% of steady-state response (i.e. 95% of final value of reactive power) as listed

in Table 6. 5.


Figure 6. 5 Response to voltage control function

No. Period (s) Voltage at the PCC (V) Reactive Power (W) Time Response (s)

1. 3.1≤t<5 20,000 -10,950 to 13 0.7

(i.e. at second 3.8)

2. 5≤t<7 19,500 125,400 to 236,800 0.5

(i.e. at second 5.5

3. 7≤t<9 20,540 -40,080 to -258,300 0.6 (at second 7.6)

Table 6. 3 Parameters in response to voltage control function


No. Time (s) Voltage at

the PCC (V)

Active

Power (W)

Theoretical

Reactive

Power (W)

Generated

Reactive

power (W)

Reactive

Power

Discrepancy

(%)

1. 3.09 20,040 995,600 -10,930 -10,970 0.037

2. 4.99 20,000 992,700 0 -14.2 -

3. 6.99 19,500 995,300 236,600 236,500 -0.04

4. 8.99 20,540 995,500 -256,800 -256,900 -0.04

Table 6. 4 Parameters in determinate points for each period

Figure 6. 6 Response to voltage control function with different parameters


Table 6. 5 Parameters in response to another voltage control function

No. Time (s) Voltage at

the PCC (V)

Active

Power (W)

Theoretical

Reactive

Power (W)

Generated

Reactive

power (W)

Reactive

Power

Discrepancy

(%)

1. 3.09 20,040 995,600 -10,930 -10,970 0.37

2. 4.99 20,000 992,700 0 -14.2 -

3. 6.99 17,000 995,000 616,100 616,200 0.02

4. 8.99 23,000 995,500 -618,300 -617,800 -0.08

Table 6. 6 Parameters in determinate points for each period

6.2.2 Reactive Power Control

As described earlier in section 3.3.3 Reactive Power and Voltage Support particularly in Table

3.29, the grid code proposal contains reactive power regulation for solar PVPP in major islands

and small islands in Indonesia.

The proposed reactive power control is adopted from Denmark´s grid code and it is applied to

solar PVPP in both major islands and small islands. As set out in the grid code proposal, the

1 MW solar PVPP must be capable of delivering reactive power ranging from 0.48 pu to -0.48

pu with respect to power factor from 0.9 to -0.9.

No. Period (s) Voltage at the PCC (V) Reactive Power (W) Time Response (s)

1. 3.1≤t<5 20,000 -10,950 to 13 0.7

(i.e. at second 3.8)

2. 5≤t<7 17,000 370,800 to 618,400 0.5

(i.e. at second 5.5

3. 7≤t<9 23,000 -241,600 to

-619,300

0.7 (at second 7.7)


In this simulation, the maximum and minimum allowable reactive power setpoint of 0.48 pu

and -0.48 pu, respectively, are separately applied. At the same time, the MPPT mode

particularly maximum active power is engaged. As depicted in Figure 6. 7, the simulation

results are shown from second 0.2 because initialization that is unrelated to the simulation

analysis takes place until second 0.2. It is observed that at second 0.2 solar PVPP starts to

increase active power from 814,900 W and at second 2.5 solar PVPP attains the maximum

PVPP power of 993,600 W. Concurrently, the reactive power setpoint (𝑄∗) is set to 0.48 pu

at second 0.2 then the solar PVPP starts delivering reactive power gradually from 273,100

W. Then solar PVPP attains the reactive power setpoint (𝑄∗) of 476,928 W at second 1.8.

In other words, it takes 1.6 s for solar PVPP to attain the reactive power setpoint (i.e. time

response of 1.6 s).

Additionally, as illustrated in Figure 6. 8, when the reactive power setpoint is established at

-0.48 at second 0.2 then the solar PVPP starts absorbing reactive power of -272,800 W.

The solar PVPP reaches the reactive power setpoint (𝑄∗) of -476,928 W at second 1.7 s. In

other words, it takes 1.5 s for solar PVPP to reaches the reactive power setpoint (i.e. time

response of 1.5 s). At the same time, at second 0.2 the MPPT mode particularly maximum

power point is engaged. The solar PVPP begin producing active power 814,900 W and

reaches the active power setpoint of 993,600 W at second 2.5. It is concluded that the

proposed reactive power controller meets the requirement as it gives time response shorter

than that in the requirement (i.e. time response of 10 s).

Figure 6. 7 Response to maximum allowable reactive power setpoint


Figure 6. 8 Response to minimum allowable reactive power setpoint

6.2.3 Power Factor Control

As explained in section 3.3.3 Reactive Power and Voltage Support, solar PVPP both in major

islands and smalls islands must be capable of operating at power factor in the range of 0.9 to

-0.9. In this simulation, the maximum and minimum permissible power factor setpoint of 0.9

and -0.9 are applied separately. At the same time, MPPT particularly MPP mode is activated.

As depicted in

Figure 6. 9, the simulation results are shown from second 0.2 because initialization that is

unrelated to the simulation analysis takes place until second 0.2. At second 0.2, it is

observed that the solar PVPP starts to increase active power from 814,900 W and at second

2.5 solar PVPP attains the maximum PVPP active power of 993,600 W. And at second 0.2,

when the power factor setpoint is established at 0.9, the solar PVPP also starts delivering

reactive power gradually from 208,400 W. Then eventually the solar PVPP attains the

desired reactive power of 476,928 W at second 2.3. Regarding the response to power factor

setpoint, at second 0.2, solar PVPP operates at power factor of 0.96 and eventually at

second 2.9, it attains the reactive power setpoint of 0.9. In other words, the solar PVPP

attains the steady-state response of power factor setpoint in 2.7 s (i.e. time response of 2.7

s).

In addition, as illustrated in Figure 6. 10, the simulation results are displayed from second 0.2

because of unrelated transient condition that lasts until second 0.2. At second 0.2, the solar

PVPP begins to deliver active power gradually from 814,900 W and at second 2.5 solar PVPP


reaches the maximum active power of 993,600 W. At second 0.2, when the power factor

setpoint is established at -0.9, the solar PVPP starts to absorb reactive power from -249,100

W. Then finally the solar PVPP reaches the desired reactive power of -476,928 W at second

2.4. Concerning response to power factor setpoint, at second 0.2, solar PVPP runs at power

factor of -0.96 and finally at second 2.7, the solar PVPP attains the power factor setpoint of -

0.9. In other words, the solar PVPP reaches the steady-state response of reactive power in

2.5 s (i.e. time response of 2.5 s). It is concluded that proposed power factor controller meets

the requirement as it yields time response less than 10 s as stated in the requirement.

Figure 6. 9 Response to maximum allowable power factor setpoint


Figure 6. 10 Response to minimum allowable power factor setpoint


Conclusion

In this master thesis, the study of several international grid codes from operational

perspectives are performed as a foundation to create grid code proposal for 1 MW solar PVPP

in Indonesia. The grid code proposal consists of regulation of voltage and frequency boundary,

active power and frequency support, reactive power and voltage support as well as fault-ride-

through (FRT). Moreover, to comply with the grid code proposal, power plant controller (PPC)

is modelled and simulated using Matlab and Simulink to see the response. Particularly, MPPT

function in PV inverter and voltage control, reactive power control and power factor control

have been verified. Following conclusions can be drawn from all works carried out in this

master thesis.

• At present, Indonesia is using IEEE series of standard and one of them is IEEE 1547 as

the guidance on interconnection of solar PVPP to electricity grid. The current policies in

Indonesia are leading to promote the connection of new PV generation facilities, which

will change the electricity mix of the country. Accordingly, new regulations regarding the

PV power plants interconnection will be required.

• This study can serve as a starting point for developing a new regulation for the

connection of PVPP in Indonesia. From the viewpoint of geography, electricity

generation mix and electricity interconnection system those grid codes that best suit

the solar PVPP in major island and small islands are grid code of Denmark and Puerto

Rico, respectively. Moreover, based on these two international grid codes, the grid code

proposal is created along with some modifications to adapt to the existing electricity

system of Indonesia and projection of solar PV growth in the electricity mix.

• As working temperature (T) and solar irradiance (G) affects the active power output of

solar PVPP, it is necessary to use MPPT function to continuously search for the

maximum power point (MPP). Maximum power point (MPP) mode in MPPT function is

modelled and simulated under variation of working temperature (T) and solar irradiance

(G). It is validated that MPP mode helps to produce maximum active power in each

scenario.

• In order to comply with the grid code proposal such as active power and frequency

regulation as well as reactive power and voltage regulation, MPPT function and power

plant controller (PPC) is modelled and developed. MPPT function can be modified in

order to achieve a desired power production. This modification can be used to comply

with those requirements affecting the active power (e.g. power curtailment) as shown

by the simulation results.


• The voltage, reactive power and power factor control requirements can be fullfilled

thanks to a central controller based on a PI controller, which have been validated

through simulations complying with the required time response.

In order to obtain more comprehensive and accurate result, the following works can be carried

out in the future.

• In order to see the dynamic response and effect of individual electrical device, the

current solar PVPP model can be developed to detailed solar PVPP model comprising

LV-MW transformer and MV-MV transformer.

• In order to see the response to active power and frequency regulation, the active power

and frequency support controller comprising function of frequency response (i.e.

frequency control), absolute production (i.e. power curtailment), delta production (i.e.

power reserve) and power gradient (i.e. ramp rate) can be modelled and simulated.


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